Control of Hazardous Air Pollutants From Mobile Sources
[Federal Register: February 26, 2007 (Volume 72, Number 37)]
[Rules and Regulations]
[Page 8477-8526]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26fe07-20]
[[pp. 8477-8526]]
Control of Hazardous Air Pollutants From Mobile Sources
[[Continued from page 8476]]
[[Page 8477]]
comply with the fleet average standard. We also cannot reasonably
assume that an ICI that certifies and produces vehicles one year, will
certify or even be in business the next. Consequently, we are
finalizing the proposed provision barring ICIs from utilizing the
deficit carry forward provisions of the ABT program.
VI. Gasoline Benzene Control Program
A. Description of and Rationale for the Gasoline Benzene Control Program
We received comments on a wide range of issues regarding our
proposal of a gasoline benzene control program. We have considered
these comments carefully. This notice finalizes a gasoline benzene
control program that is very similar to the proposed program, with the
inclusion of an upper limit benzene standard on which we sought comment.
The gasoline benzene control program has three main components,
each of which is discussed in this section:
--A gasoline benzene content standard. In general, refiners and
importers will be subject to an annual average gasoline benzene
standard of 0.62 volume percent (vol%), beginning January 1, 2011. This
single standard will apply to all gasoline, both reformulated gasoline
(RFG) and conventional gasoline (CG) nationwide (except for gasoline
sold in California, which is already covered by a similar state program).
--An upper limit benzene standard. In general, this ``maximum average
standard'' will require that the annual average of actual benzene
levels that each refinery produces be less than or equal to 1.3 vol%
without the use of credits, beginning July 1, 2012.\177\
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\177\ The per-gallon benzene cap (1.3 vol%) in the RFG program
will continue to apply separately.
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--An averaging, banking, and trading (ABT) program. The ABT program
allows refiners and importers to choose the most economical compliance
strategy (investment in technology, credits, or both) for meeting the
0.62 vol% annual average benzene standard. The program allows refiners
to generate ``early credits'' for making qualifying benzene reductions
earlier than required and allows refiners and importers to generate
``standard credits'' for overcomplying with the 0.62 vol% benzene
standard in 2011 and beyond. Credits may be used interchangeably
towards compliance with the 0.62 vol% standard, ``banked'' for future
use, and/or transferred nationwide to other refiners/importers subject
to the standard. While credits may not be used to demonstrate
compliance with the 1.3 vol% maximum average standard, the ABT program
in its entirety provides the refining industry with significant
compliance flexibility. To achieve compliance with the 0.62 vol%
average standard in 2011 and beyond, refiners and importers may use
credits generated and/or obtained under the ABT program, reduce their
gasoline benzene levels, or any combination of these.
--Provisions for refiners facing economic hardship. Refiners approved
as ``small refiners'' will have access to special temporary relief
provisions. In addition, any refiner facing extreme unforeseen
circumstances or extreme hardship circumstances can apply for temporary
relief.
1. Gasoline Benzene Content Standard
a. Description of the Average Benzene Content Standard
The program finalized in this rule requires significant reductions
in the average levels of benzene in gasoline sold in the U.S. Beginning
in 2011, the average benzene level of all batches of gasoline produced
during a calendar year at each refinery will need to be at or below a
standard of 0.62 vol% benzene. Approved small refiners must comply with
this requirement by 2015. Each gasoline importer will need to meet the
0.62 vol% standard on average for its imported gasoline during each
year. The 0.62 vol% average standard may be met through actual
production/importation of fuel with a benzene content of 0.62 vol% or
less, on average, and/or by using benzene credits. A deficit is created
when compliance is not achieved in a given year. This deficit may be
carried forward without regulatory approval but must be made up the
next year. (See VI.B (Implementation), below.) While this subsection
focuses on the 0.62 vol% average standard, refiners and importers will
also be subject to a ``maximum average benzene standard'' of 1.3 vol%,
which is discussed below in section VI.A.1.d.
The 0.62 vol% average benzene standard applies to all gasoline,
both RFG and CG. Gasoline sold nationwide is covered by the standard,
with the exception of gasoline sold in California. California gasoline
is covered by existing State of California benzene requirements that
result in benzene reductions similar to the federal program finalized here.
The 0.62 vol% average benzene standard and the 1.3 vol% maximum
average standard result in air toxics emissions reductions that are
greater than required under all existing gasoline-related MSAT
programs. As a result, upon implementation in 2011, the regulatory
provisions for this gasoline benzene control program will become the
regulatory mechanism used to implement the RFG and CG (Anti-Dumping)
annual average toxics performance requirements and the annual average
benzene content requirement for RFG. The current RFG and Anti-Dumping
annual average toxics provisions thus will be replaced by this benzene
control program. This final benzene control program will also replace
the requirements of the 2001 MSAT rule (``MSAT1''). In addition, the
program will satisfy certain conditions of the Energy Policy Act of
2005 (EPAct) and thus remove the need to revise individual MSAT1 toxics
baselines for RFG otherwise required by the EPAct. In all of these
ways, this program will significantly consolidate and simplify the
existing national fuel-related MSAT regulatory program while achieving
greater overall emission reductions.\178\ See Section VI.C below for
additional discussion of this issue.
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\178\ Although this program will supersede several compliance
requirements from other programs, we are retaining certain
recordkeeping and reporting requirements from these programs. For
example, refiners will need to continue to provide gasoline fuel
property data for more than just benzene. This is discussed in more
detail in VI.B below.
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b. Why Are We Finalizing a Benzene Content Standard?
As discussed in the proposal, we believe a benzene content standard
is the most cost-effective and most certain way to reduce gasoline
benzene emissions from vehicles. Fuel benzene reductions directly and
demonstrably result in benzene emissions reductions which also results
in overall MSAT emission reductions. Focusing MSAT control on benzene
alone means that the effectiveness of the control will not be affected
by changes in fuel composition or vehicle technology. Because benzene
is a small component of gasoline (around 1 vol%), gasoline octane is
not significantly affected by a reduction in benzene content. Other
fuel changes that could be undertaken to reduce MSATs would
significantly impact octane, and replacing that octane would be costly
and could increase emissions of MSATs other than benzene. Nonetheless,
in addition to proposing to control fuel-related MSAT emissions by
means of a gasoline benzene content standard, we sought comment on a
[[Page 8478]]
number of alternative approaches, including control of toxics in
addition to benzene and more stringent limits on gasoline sulfur and
volatility. A number of commenters expressed support for some of these
alternatives and others opposed them. In reaching our decision to
finalize a benzene content standard, we evaluated the comments on each
of the alternative approaches, and we discuss these next.
i. Standards That Would Include Toxics Other Than Benzene
We considered separate standards for each of the key fuel-related
toxics (we discuss control of aromatic compounds separately) as well as
a total toxics performance standard.
A Standard for Total Toxics Performance
Several commenters advocated a standard in the form of a toxics
emissions performance standard, analogous to the current MSAT1 and RFG
standards. Some commenters requested an air toxics standard in addition
to the fuel benzene content standard we are finalizing. In general,
these commenters expressed concern that if toxics other than benzene
are not also controlled simultaneously, refiners may allow the
emissions of these other compounds to increase, even while benzene is
being reduced. Other commenters requested a toxics standard instead of
fuel benzene control (or as an alternative compliance option). These
commenters felt that a toxics performance standard offered more
compliance flexibility. Other commenters supported our proposed
benzene-only standard, stating that a total toxics standard would add
complexity without additional benefit.
For several reasons, we continue to believe that a benzene-only
standard is superior to a toxics emissions performance standard. First,
because controlling benzene is much more cost-effective than
controlling emissions of other MSATs, refiners historically have
preferentially reduced benzene under the MSAT1 and other air toxics
control programs. This is despite the theoretical flexibility that
refiners have under a toxics performance standard to change other fuel
parameters instead of benzene. Thus, even if we were to express the
proposed standard as an air toxics performance standard, we would
expect the outcome to be the same--refiners would reduce benzene
content and leave unchanged the levels of other MSATs.
Even with, or as a result of, this fuel benzene control, we do not
expect refiners to actively modify their refinery operations such that
increases will occur in emissions of the other MSATs currently
controlled under the toxics performance standards. These other MSATs
are acetaldehyde, formaldehyde, POM, and 1,3-butadiene, and they are
all affected to varying degrees by VOC emissions control. VOC emissions
are generally decreasing due to the gasoline sulfur controls recently
phased in along with tighter vehicle controls under the Tier 2 program,
as well as the vehicle controls being finalized under this program (see
section V above). In combination, these changes are expected to
decrease VOC-based MSAT emissions substantially.
In addition to reductions because of declining VOC emissions,
formaldehyde emissions are currently, and for the foreseeable future,
declining as MTBE use ends. See 71 FR 15860.
According to the Complex Model, the Agency's current gasoline
emissions compliance model, POM emissions correlate directly with VOC
emissions (see 40 CFR 80.45(e)(8). Therefore, we expect significant POM
emission reductions as VOC emissions decline.
For 1,3-butadiene, the fuel parameter of interest is olefins.
Increasing olefins increases 1,3-butadiene emissions. However, olefins
are expected to decrease as a result of the implementation of the
gasoline sulfur program because they are reduced along with sulfur
during the desulfurization process. Olefins are also often used for
their octane value, but because of increased ethanol use, this need
should be reduced. As a result, we do not expect refiners to take
actions to increase olefins, and thus 1,3-butadiene emissions should
not increase. Also, 1,3-butadiene, like other MSATs, is reduced when
VOC is reduced due to fuel and vehicles standards being implemented
(see 71 FR 15860).
The one MSAT likely to increase in the future is acetaldehyde.
Current market forces, along with state and federal policies and
requirements such as the proposed Renewable Fuels Standard (RFS)
Program,\179\ ensure that ethanol use will increase, and thus
acetaldehyde as well, since that MSAT is directly and substantially
affected by ethanol use. Acetaldehyde emissions are currently about
one-seventh the magnitude of benzene emissions from motor vehicles, but
are increasing (while formaldehyde emissions are decreasing) due to the
substitution of ethanol for MTBE in RFG as a result of state MTBE bans.
Any action that refiners could take to offset the total toxics increase
as a result of acetaldehyde increasing would be through benzene
control, which we are already requiring to be controlled to the maximum
extent possible. The EPAct, which charged EPA with developing the RFS
program, also requires an evaluation of that Act's impacts on air
quality. Any future control of acetaldehyde emissions will be based
primarily on the results of that study. EPA thus believes it premature
to act until we determine a course of future action reflecting the
EPAct study, a draft of which is due to Congress in 2009.
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\179\ 71 FR 55552, September 22, 2006.
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As described above, with the exception of acetaldehyde, the benzene
control program will ensure the certainty of additional MSAT
reductions. Other MSAT emissions are thus unlikely to increase under
this program. Because an air toxics standard would not provide any
additional emission reductions, we believe that the regulatory
controls, and the associated paperwork and the other administrative
costs that would result if standards explicitly including these other
MSATs were adopted, are not necessary. The benzene control program will
thus ensure the certainty of additional MSAT reductions. A toxics
emissions performance standard that would effectively achieve the same
level of MSAT reduction would be more costly and complex. For all of
these reasons, we believe a standard in the form of a benzene content
standard will produce more certain environmental results with less
complexity than a toxics emissions performance standard, and we are
therefore finalizing only a benzene content standard.
A Standard for Aromatic Compounds in Addition to Benzene
In the proposal, we considered MSAT control through the reduction
of the content of aromatics in addition to benzene in gasoline. For a
number of reasons, we did not propose such control (see 71 FR 15860 and
15864). During the comment period, we received comments urging EPA to
impose controls on non-benzene gasoline aromatic compounds, in addition
to controlling benzene. These commenters believe aromatics control
would provide more toxics emissions reductions than a benzene-only
control program, and they also believe it would improve air quality by
significantly reducing fine particulate matter. Expanded use of E85 and
flexible-fuel vehicles and ETBE were suggested as ways to replace the
octane value which would be lost if aromatics were reduced. They also
cited other benefits such as energy independence and reduction of trade
deficits, and stated that costs to
[[Page 8479]]
the refining industry would not be significant. A significant rebuttal
to this request for aromatics control was presented by the refining
industry.
We note first that regardless of specific regulatory action to
control aromatics, the increased use of ethanol in response to current
market forces and state and federal policies (including the RFS
program) will contribute to lower aromatics levels. This will occur for
two reasons. First, ethanol has historically been blended downstream of
refineries, either as a ``splash blend'' or as a ``match blend.'' In a
splash blend, the ethanol is mixed with finished gasoline. In a match
blend, refiners prepare a special subgrade of gasoline that, when
blended with ethanol, becomes finished gasoline. In recent years, match
blending has increased as refiners have been producing RFG with
ethanol, and it is expected to increase even more as ethanol use
expands. A splash blend will reduce aromatics by about 3 vol% by simple
dilution.\180\ A match blend will reduce aromatics by about 5
vol%.\181\ With ethanol use expected to more than double, we expect a
significant reduction in aromatics levels. Second, with all of this
ethanol there will be excess octane in the gasoline pool. Thus, not
only will increased ethanol use decrease aromatics concentrations
through dilution, but refiners will make the economic decision to use
ethanol to reduce or avoid producing aromatics for the purpose of
increasing octane.
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\180\ If the aromatics content of a gallon of gasoline is 30
vol%, adding 10% ethanol dilutes the aromatic content to about 27
vol%.
\181\ Section 2.2 ``Effects of Ethanol and MTBE on Gasoline Fuel
Properties'' in the Renewable Fuel Standard Program: Draft
Regulatory Impact Analysis, September, 2006.
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Because of differences in how refiners will respond to the rapid
increase in ethanol use, it would be difficult to determine an
appropriate level for an aromatics standard at this time. The gasoline
market is going through an historic transition now due to the removal
of MTBE, conversion of some portion of the MTBE production volume to
other high octane blendstock production, growth of ethanol use, and the
rise in crude oil prices. Consequently, it is difficult to reliably
project a baseline level of aromatics for the gasoline pool with any
confidence. This is compounded by a great deal of uncertainty in
knowing how much of the market ethanol will capture. Projections by EIA
are significantly higher now than just a few months ago, and
Presidential and Congressional proposals could easily result in 100% of
gasoline being blended with ethanol. Second, aromatics levels vary
dramatically across refineries based on a number of factors, including
refinery configuration and complexity, access to other high octane
feedstocks, access to the chemicals market, crude sources, and premium
grade versus regular grade production volumes. Third, without knowing
with some certainty the range of aromatics contents of refineries'
gasoline, we cannot determine the greatest degree of emission reduction
achievable, and also cannot make reasonable estimates regarding cost,
lead time, safety, energy impacts, etc. As a result, at this time we
would not be able to determine an appropriate or meaningful aromatics
standard.
For the purpose of reducing total toxics emissions, fuel benzene
control is far more cost-effective than control of total aromatics, for
a number of reasons. As we explained in the proposal, reducing the
content of other aromatics in gasoline is much less effective at
reducing benzene emissions than reducing fuel benzene content. Based on
the Complex Model,\182\ roughly 20 times greater reduction in total
aromatics content is needed to achieve the same benzene emission
reduction as is achieved by fuel benzene reductions. At the same time,
to broaden the program to control other aromatics would result in a
significant octane loss. While we have not yet conducted a thorough
refinery modeling evaluation, based on existing refinery and market
information the alternative sources of octane (other than ethanol)
appear to be of limited supply and would be of limited effectiveness in
replacing the octane lost from any fuel aromatics reductions.
Furthermore, as noted above, the uncertainty in the extent to which
ethanol will penetrate the market makes it difficult to project the
potential replacement of aromatics with ethanol. Any significant
reduction in aromatics would also affect the gasoline and diesel sulfur
reduction programs because hydrogen, which is used in the
desulfurization process, is produced when aromatics are produced. If
refiners were required to reduce their aromatics levels, costs would
increase further because some would have to expand or build new
hydrogen production facilities.
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\182\ Total toxics emissions are as calculated by the Complex
Model. This model is the tool used to determine compliance with the
toxics emissions controls in the RFG, Anti-dumping, and MSAT1
programs. Cost estimates for aromatics control and analysis of
relative benzene emissions with control of aromatics and benzene are
found in Regulation of Fuels and Fuel Additives; Standards for
Reformulated and Conventional Gasoline; Final rule, Table VI-A6 of
the Regulatory Impact Analysis, February 16, 1994.
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Reducing aromatics would also raise other environmental concerns
that would need to be addressed in any regulation. Actions available to
refineries for replacing octane, including adding ethanol, can increase
other MSATs, as mentioned above. In addition, some commenters
encouraged the use of the ether derived from ethanol, ETBE, to make up
octane. Any regulatory action that required or was based on the use of
ETBE would likely raise issues of potential groundwater contamination
given the groundwater contamination caused by the use of the chemically
similar MTBE.
There may be compelling reasons to consider aromatics control in
the future, especially regarding reduction in secondary
PM2.5 emissions, to the extent that evidence supports a role
for aromatics in secondary PM2.5 formation.\183\
Unfortunately, there are limitations in both primary and secondary PM
science and modeling tools that limit our present ability to
quantitatively predict what would happen for a given fuel control.
Thus, at this point, we do not feel that the existing body of
information and analytical tools provide a sufficient basis to
determine if further fuel aromatics control is warranted. However, we
do feel that additional research is very important. Test programs and
analyses are planned to address primary PM issues, including those
examining the role of aromatics. Also, more work is underway on how
fuel aromatics, including toluene, affect secondary PM formation, and
how aromatics control should be incorporated into air quality
predictive models.\184\
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\183\ See Chapter 1 in the RIA for more on current studies on
this subject.
\184\ See Chapter 1 in the RIA for more on current studies on
this subject.
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In summary, we believe that aromatics levels will be falling even
without an aromatics standard, and aromatics control will need to be
evaluated in the context of what might be possible beyond what will
occur through the expanded use of ethanol. Furthermore, any additional
control would be costly and raise a number of other issues which need
further investigation before EPA could responsibly initiate such a
control effort. Thus, we have concluded that additional aromatics
control for MSAT purposes is not warranted at this time.
[[Page 8480]]
ii. Control of Gasoline Sulfur and/or Volatility for MSAT Reduction
In the proposal, we outlined a number of issues related to further
control of gasoline sulfur content and volatility (usually described as
Reid vapor pressure, or RVP) as a means of MSAT emissions
reduction.\185\ (See 71 FR 15861-62.) In both cases, there was
insufficient data on newest technology vehicles at that time to
evaluate their effectiveness as MSAT controls. Therefore, we did not
propose changes to existing standards.
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\185\ For further discussion of the impact of these fuel
properties on emissions, see RIA Chapter 7.
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We received several comments related to sulfur and RVP control, but
there was general agreement in the comments from auto manufacturers and
refiners that sufficient data does not yet exist for EPA to take action
as a part of this rule. Consequently, we are not taking action to adopt
additional control of gasoline sulfur or RVP. However, since the
proposal, we have completed a small fuel effects test program in
cooperation with several automakers to help evaluate the impact of fuel
property changes on emissions from Tier 2 vehicles. These data suggest
that reducing gasoline sulfur below 30 ppm could bring significant
reductions in VOC and NOX, but the data relating to air
toxics reductions were not statistically significant. Unlike past
programs on older technology vehicles, these data suggest that reducing
gasoline volatility from 9 to 7 psi RVP under normal testing conditions
(75[deg] F) may actually increase exhaust toxics emissions. The program
did not examine the impacts of fuel volatility on evaporative
emissions. These data indicate that there may be benefits to future
fuel control but that more testing is warranted. More details on the
test program and its results are available in Chapter 6 of the RIA.
iii. Diesel Fuel Changes
In the proposal, EPA did not propose additional controls on diesel
fuel for MSAT control. We continue to believe that the recent highway
and nonroad diesel programs (see section IV. D. 1. c above) will
achieve the greatest currently achievable reductions in diesel-related
MSAT control (i.e., reductions in emissions of diesel particulate
matter and exhaust organic gases). These emission reductions will
result from the deep cuts in diesel fuel sulfur that will be
implemented in the same time frame as this gasoline benzene rule, along
with the associated diesel engine emission control requirements of the
diesel programs. We said that we were unaware of other changes to
diesel fuel that could have a significant effect on MSAT emissions, and
requested comment about limiting this action to gasoline benzene.
One group of commenters stated in joint comments that they believe
that EPA needs to do more to protect human health and the environment
from the effects of diesel exhaust emissions. While they specifically
mention actions to accelerate the introduction of cleaner diesel
engines, they do not suggest any additional changes to diesel fuel.
Another commenter, a refiner, believes that further diesel fuel
controls are not warranted.
Some commenters support control of the polyaromatic hydrocarbon
(PAH) content of diesel fuel. The actions refiners are taking to
produce ultra-low sulfur diesel fuel (15 ppm sulfur) are expected to
reduce the PAH content in diesel fuel.\186\ In addition, available data
indicate that the advent of exhaust emission controls on diesel engines
under the recent diesel programs will reduce exhaust PAH, regardless of
any changes to diesel fuel.
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\186\ Control of Emissions of Air Pollution from Nonroad Diesel
Engines and Fuel--Final Rule, Section 5.9.4 of the Regulatory Impact
Analysis, June 29, 2004.
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We continue to believe that existing regulations will achieve the
greatest currently achievable reductions in MSAT emissions from diesel
engines. EPA will continue to monitor MSAT issues related to diesel
fuel. For example, there are active programs underway to measure PAH
exhaust emissions from diesel engines meeting the 2007 PM engine
standards.\187\ However, at this time, we are not aware of diesel fuel
controls that could significantly affect MSAT emissions and commenters
did not offer specific information to the contrary. Consequently, we
have focused our fuel-related MSAT action on gasoline benzene, as proposed.
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\187\ Health Effects Institute's Advanced Collaborative Emissions Study.
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c. Why Are We Finalizing a Level of 0.62 vol% for the Average Benzene
Standard?
We considered a range of average benzene standards, taking into
account technological feasibility as well as cost and the other
enumerated statutory factors. We received comments from a variety of
parties supporting standards more stringent than the proposed level of
0.62 vol%. In general, the refining industry did not express strong
opposition to a standard of 0.62 vol%. However, several small refiners
opposed a benzene standard and argued for relief for small refiners if
EPA went forward with such a program. One commenter, an importer,
proposed a standard of 1.0 vol%. None of the commenters opposing the
0.62 vol% standard provided analytical support for a less stringent
standard, or addressed how a less stringent standard might reflect the
greatest emission reductions achievable based on the statutory factors.
We have considered all of these comments and reassessed the level of
the standard in light of the key factors we are required to consider,
and have concluded that, as proposed, 0.62 vol% is the appropriate
level for the average standard, because it achieves the greatest
achievable emission reductions through the application of technology
that will be available, considering cost, energy, safety, and lead
time.\188\ As discussed in section VI.A.1.d below, we have drawn this
conclusion in the context of the 1.3 vol% maximum average benzene
standard. We summarize our assessment of technological and economic
factors next.
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\188\ EPA does not believe that there are any noise issues
associated with these standards, and no comments suggested any such
issues exist.
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i. General Technological Feasibility of Benzene Control
Benzene Control Technologies
We have identified several technologies that can cost-effectively
reduce gasoline benzene levels and we assessed their feasibility. These
benzene control technologies function primarily by controlling the
benzene in the feedstock to and the product stream from the reformer.
They primarily focus on the reformer because refiners rely on the
reformer to produce aromatic compounds for their octane content, and
benzene is one of the aromatic compounds produced. For refiners who are
not actively reducing the benzene in their gasoline today, we estimate
that the reformer is responsible for about one half to three quarters
of the benzene in gasoline.
Since the proposal, we learned of a change in how a particular
gasoline blending stream is being routed in the refinery which affects
its treatability for reducing benzene. After speaking to several
refiners, we learned that natural gasoline is being blended differently
into gasoline today because of the need to address the sulfur in this
stream for compliance with Tier 2. Specifically, natural gasoline is
being blended with the crude oil before the crude oil is refined in the
refinery. Therefore the benzene in natural gasoline would be treated
along with the naturally occurring benzene in crude oil using the
[[Page 8481]]
benzene control technologies described below. We reflected this change
in our refinery modeling.
One approach to reducing gasoline benzene levels is to reroute
around the reformer the intermediate refiner streams that have the
greatest tendency to form benzene in the reformer. This technology is
usually termed light naphtha splitting. Assuming that a refinery
applying this technology is not applying any sort of benzene control
today, we estimate that this method reduces the benzene levels of
reformate (the stream leaving the reformer) by 60 percent. This
approach requires little or no capital investments in refineries to
realize the results, but its effectiveness is limited because it does
not address any of the naturally-occurring benzene found in crude oil
and from natural gasoline and the other benzene which is formed in the
reformer. Although this benzene control technology normally will not
achieve the most substantial benzene control, refiners choosing it will
achieve some measure of benzene control and then would likely need to
purchase credits to comply with the 0.62 benzene standard.
To achieve deeper benzene control, refiners with an isomerization
unit can send the rerouted intermediate refinery stream to their
isomerization unit. The isomerization unit would saturate the
naturally-occurring benzene from crude oil and natural gasoline in the
rerouted refinery intermediate stream mentioned above, thus achieving
additional benzene reduction. Using these two technologies together,
refiners will be able to reduce reformer benzene levels by an estimated
80 percent. However, the benzene formed in the reformer would still not
be treated using these two technologies together.
For even deeper benzene reductions than benzene precursor rerouting
by itself or in combination with isomerization, refiners could choose
between benzene saturation and benzene extraction. Each of these
technologies work by reducing the benzene levels in the reformate,
achieving an estimated 96 percent reduction in benzene, assuming that
the refinery is not already taking steps to control its benzene levels.
Benzene saturation involves using hydrogen to saturate the benzene into
cyclohexane, which is a compound usually found in gasoline. Benzene
extraction units chemically extract the benzene from the rest of the
hydrocarbon compounds in reformate and concentrate it to a high purity
using distillation such that it is suitable for sale into the chemicals
market. Either of these technologies is capable of achieving the
deepest levels of gasoline benzene reductions, allowing virtually all
refiners to meet or exceed the 0.62 vol% gasoline benzene standard.
The actual impact of these benzene control technologies on an
individual refinery's finished gasoline benzene content, however, will
be a function of many different refinery-specific factors. These
factors include the types of refining units in each refinery and the
benzene levels produced by them, and the extent to which they are
already utilizing one or more of these benzene control technologies.
Each of the benzene control technologies associated with the
reformer has been commercially demonstrated by at least half a dozen
units in U.S. refineries today operating for at least two years. Also,
we did not receive any comments questioning the viability of these
technologies for achieving the benzene reduction attributed to these
technologies in the proposed rule. We therefore conclude that these
technologies can feasibly achieve the benzene reductions that we
attribute to them. We discuss the economics for each of these
approaches to benzene reduction in more detail in section VIII.A. of
this preamble, and we discuss their feasibility and cost in detail in
Chapters 6 and 9 of the RIA.
We evaluated the benzene control level achievable without the use
of credits by each refinery using either benzene saturation or
extraction, since this would represent the maximum technologically
feasible level of benzene control by each refinery. Our refinery cost
model shows that based on the application of one or the other of these
two benzene technologies, eight refineries would still not be able to
achieve the final 0.62 vol% benzene average standard. We believe that
these refineries would, however, be able to achieve the 1.3 vol%
maximum average standard (which, as explained in section VI.A.1.d
below, must be achieved without the use of credits) through the use of
one of these technologies.
These eight refineries would be able to further reduce their
gasoline benzene levels by treating the benzene contained in other
gasoline blendstocks, particularly light straight run, light coker
naphtha and light hydrocrackate. We believe that refiners could merge
these streams with their reformate gasoline stream, so that these other
sources of benzene would be treated along with the benzene in the
reformate using either benzene saturation or benzene extraction. The
results of this additional analysis summarized in the RIA show that
these eight refineries would be able to meet the 0.62 vol% average
standard if they were to apply one or more of these additional benzene
control steps, though in some cases it may be at a considerably higher
cost than through the purchase of credits. The cost and ultimate
feasibility for controlling the benzene in light straight run, light
coker naphtha and light hydrocrackate is very difficult to determine
without detailed and comprehensive knowledge about how refineries are
configured and operated today. It might be possible for a refinery to
adjust existing distillation units, either operationally or with minor
capital investments, to change the cutpoints for these streams. They
might then route the benzene in these streams to the reformer, where a
benzene control technology would be applied. On the other hand,
changing the cutpoints to reroute the benzene might require the
addition of a whole new distillation column, similar in function to a
reformate splitter. Adding such grassroots distillation columns to make
these splits would be much more costly. Finally we have not found any
commercially demonstrated benzene control technologies that can reduce
the benzene of FCC naphtha, the second largest contributor of benzene
to the gasoline pool.
Impacts on Octane and Strategies for Recovering Octane Loss
All these benzene reduction technologies tend to cause a small
reduction in the octane value of the final gasoline, since benzene is
high in octane (about 101 octane number ((R+M)/2). Understanding how
lost octane will be recovered is critical to determining the
feasibility and cost of benzene control. Regular grade gasoline must
comply with a minimum 87 octane number (or a sub-octane rating of 86
for driving in altitude), while premium grade gasoline must comply with
an octane rating which ranges from 91 to 93 octane numbers. Gasoline
must meet these octane ratings to be sold at retail. Routing the
benzene precursors around the reformer reduces the octane of the six-
carbon compound stream (by foregoing the formation of benzene) which
normally exits the reformer with the rest of the reformate. Without
these compounds in the reformate, our refinery model shows that a loss
of octane in the gasoline pool of about 0.14 octane numbers will
typically occur. If this rerouted stream can be sent to an isomerization
unit additional octane loss will occur due to the saturation of
[[Page 8482]]
benzene \189\; however, as described below, the isomerization unit
offsets a part of the octane loss caused by this combination of
saturation and rerouting. Benzene saturation and benzene extraction
both affect the octane of reformate and therefore of the gasoline pool.
Our refinery model estimates that benzene saturation typically reduces
the octane of gasoline by 0.24 octane numbers, and benzene extraction
typically reduces the octane of gasoline by 0.14 octane numbers.
---------------------------------------------------------------------------
\189\ The chemical process of benzene saturation in the
isomerization unit is the same as the process that occurs in a
benzene saturation unit, as described above.
---------------------------------------------------------------------------
Refiners have several choices available to them for recovering the
lost octane. One is to blend in ethanol. Ethanol has a very high octane
number rating of 115. Thus, only a small amount of ethanol (one percent
of the gasoline pool or less) would be necessary to offset the octane
loss associated with benzene reductions. Moreover, ethanol blending
will occur for reasons independent of the benzene control requirements
(and attendant octane loss) of the present rule. As explained in the
discussion of potential aromatics controls above, current market forces
and state and federal policies (including the RFS program) will
increase the volume of renewable fuels, including ethanol, which is to
be blended into gasoline. The volume of renewable fuels must increase
from around 4 billion gallons in 2004 to 7.5 billion gallons in 2012
when the renewable fuels provisions of the RFS are fully implemented.
However, as part of the Annual Energy Outlook for 2006, the Energy
Information Administration projects that the economics driven by higher
crude oil prices will result in more like 9.6 billion gallons of
ethanol use by 2012.
Octane may also be increased by increasing the severity of the
reformer (which determines the final octane of the reformate). However,
if the refiner is reducing benzene through precursor rerouting or
saturation, this strategy can be somewhat counterproductive. This is
because increased severity increases the amount of benzene in the
reformate and thus increases the cost of saturation and offsets some of
the benzene reduction of precursor rerouting. Increasing reformer
severity also decreases the operating cycle life of the reformer,
requiring more frequent regeneration. However, where benzene extraction
is used, increased reformer severity can improve the economics of
extraction because not only is lost octane replaced by other aromatic
compounds, but more benzene is extracted and sold.
Refiners can also recover lost octane by increased use of
isomerization and alkylate units. As discussed above, saturating
benzene in the isomerization unit results in an octane loss, but the
octane loss is partially offset by the simultaneous formation of
branch-chain compounds in the isomerization unit. The isomerization
unit would only offset a portion of the octane loss caused by
saturating the benzene if the unit has sufficient capacity to treat
both the five-carbon hydrocarbons normally sent to the unit as well as
the newly rerouted six-carbon hydrocarbons. Also, many refineries
produce a high-octane blendstock called alkylate. Refiners can alter
their refineries to produce more alkylate or they may be able to
purchase alkylate on the open market. Not only is alkylate moderately
high in octane (93 or 94 octane numbers), but it converts four-carbon
(i.e., butane) compounds that are too volatile to be blended in large
amounts into the gasoline pool into heavier compounds that can be
readily blended into gasoline, thus increasing gasoline volume.
All these means available to refiners for recovering the octane
loss associated with gasoline benzene reductions are commercially
demonstrated, and we did not receive any comments questioning our
reliance on them at proposal for maintaining the octane of the gasoline
pool in the proposal. Therefore, we conclude that it is feasible for
refiners to recover the octane loss associated with benzene control.
ii. Appropriateness of the 0.62 vol% Average Benzene Content Standard
As discussed above, we received many comments about the proposed
level of the benzene standard. Many commenters advocated a more
stringent standard, generally pointing to refineries currently
producing gasoline with benzene levels below the proposed 0.62 vol%
standard and stating that the average standard should be sufficiently
stringent that all refineries, especially those with higher benzene
levels, would be required to use similar technologies and achieve
similarly low levels. We also received broad support for the 0.62 vol%
standard in the comments from the refining industry, although several
small refiners opposed imposing a benzene standard and argued for
relief for small refiners if EPA implemented the proposed standard. One
importer was concerned that the standard of 0.62 vol% could make it
more difficult for importers to find compliant gasoline shipments and
proposed a standard of 1.0 vol%. None of the commenters opposing the
0.62 vol% standard provided analytical support for a less stringent
standard or addressed how a less stringent standard might reflect the
greatest emission reductions achievable based on the statutory factors.
In the proposal, EPA described in detail what we believe would be
the consequences of average standards of different stringencies to the
overall goals of the program (see 71 FR 15866-67). These anticipated
consequences relate in large part to how we believe refiners would
respond to the benzene averaging and benzene credit trading provisions
that were integral to the proposed program. For the final rule, we have
reassessed how we believe refiners would respond to different average
standards. We continue to believe that increasing the stringency of the
average benzene standard would have the effect of reducing the number
of benzene credits generated, since fewer refineries are likely or able
to take actions to significantly reduce benzene further than required
by the standard. This would reduce the liquidity of the credit trading
market. As discussed in section VI.A.2, a well functioning averaging,
banking, and trading program is integral to the achievability of the
benzene standard. With fewer credits available that are affordable as
an alternative to immediate capital investment, investment in
relatively expensive benzene saturation equipment would be necessary
for a greater number of refiners. We specifically considered a level of
0.50 vol% for the average standard, which we expected would require all
refineries to install the most expensive benzene control technologies.
We concluded that this level would clearly not be achievable,
considering cost. In a related analysis, we also showed that if,
contrary to our expectations, credits were not easily available as a
compliance option, there are several refineries for which it may be
technologically feasible to reach benzene levels below 0.62 vol%, but
only at costs far greater than for most other refiners.
Decreasing the stringency of the standard would fail to meet our
obligation under 202(l)(2) to set the most stringent standard
achievable considering costs and other statutory factors. First, over
the last several years RFG benzene levels have already been averaging
around 0.62 vol%, and we have no information to suggest that this level
is not technologically feasible for the rest of the gasoline pool as
well. In fact, our analysis shows that this level is feasible for the
pool of gasoline as a whole. Commenters did not provide any analysis
that a standard of 0.62 vol%
[[Page 8483]]
was not the greatest achievable after considering cost and the other
statutory factors. Second, a standard less stringent than 0.62 vol%
would not achieve a number of important programmatic objectives. As
shown in Table VI.C-1 below, a 0.62 vol% standard is necessary to
satisfy the conditions on overall RFG toxics performance established by
EPAct and thus to avoid the requirement for updated individual refinery
baselines. We believe that any level for the standard above 0.62 vol%
would require EPA to promulgate regulations requiring RFG refiners to
continue to maintain individual refinery-specific baselines, adjusted
to 2001-2 as required by EPAct. The refining industry believes that
this would continue to penalize the cleanest refineries, constrain
their flexibility, and cause market inefficiencies that increase costs.
They have been strongly supportive of a program that eliminates the
need for individual refinery baselines. EPA agrees with these concerns,
and believes that the nationwide ABT program allowed under this program
will remove these impacts. Another of EPA's policy objectives that has
been strongly supported by the refining industry was establishing the
same standard nationwide for the combined pool of RFG and CG. The level
of 0.62 vol% allows us to establish a single combined program for RFG
and CG. In addition, the level of 0.62 vol% for the standard allows us
to streamline with confidence our toxics regulations for RFG and CG, so
that this benzene program (along with the gasoline sulfur program) will
become the regulatory mechanism used to implement the RFG and CG annual
average toxics performance requirements and the annual average benzene
content requirement for RFG. Further, we believe that with such a
stringent benzene standard, refiners should have the certainty they
need for their investment and planning decisions.
Many comments that supported a more stringent standard pointed to
average costs projected in the proposal that are higher than for the
proposed standard, but are not large on a per-gallon basis compared to
other EPA fuel programs. However, these commenters did not address the
wide range of compliance costs for individual refineries that we
discuss in the proposal (see Chapter 9 of the proposed and final RIA
documents). It is critical to recognize that as more stringent average
standards are considered, the costs for many refineries begin to rise
significantly, especially for some individual technologically-
challenged refineries. This potential for high costs at more stringent
average standards exists if, as we expect, the ABT program functions as
it is designed to. If the ABT program operates less efficiently than
projected, the costs for some individual refineries could be higher
still. (We discuss issues related to the 1.3 vol% maximum average
standard, which cannot be met through the use of credits, in section
VI.A.1.d, ``Upper Limit Benzene Standard,'' below.)
Based on our analysis of the projected response of the refining
industry to an average benzene standard, we are finalizing the 0.62
vol% standard as proposed. We believe that this average benzene
standard of 0.62, in the context of the associated ABT program and the
1.3 vol% maximum average standard, results in the greatest reductions
achievable, taking into account cost and the other statutory factors in
CAA 202(l)(2).
iii. Timing of the Average Standard
Section 202(l)(2) requires that we consider lead time in adopting
any fuel control for MSATs. We proposed that refiners and importers
meet the 0.62 vol% average benzene standard beginning January 1, 2011
(January 1, 2015 for small refiners). This date was based on the
industry experience that most of the technological approaches that we
believe refiners will apply--rerouting of benzene precursors around the
reformer and use of an existing isomerization unit--will take less than
two years. The more capital intensive approaches--saturation and
extraction--generally take two to three years to complete. The January
1, 2011 date provides nearly four years of lead time. We believe this
is an appropriate amount of lead time, even taking into account that
other fuel control programs (notably the Nonroad Diesel program) will
be implemented in the same time frame.
Some commenters supported earlier start dates, referring in some
cases to the experience of Canada in regulating gasoline benzene.
However, these comments failed to acknowledge the less stringent
Canadian standard (0.95 vol%) which naturally takes less lead time to
implement. No commenter provided information that challenged our
assessments of the technical lead time for the range of benzene control
approaches that will be implemented. Other commenters, mostly from the
refining industry, supported a start date that would be at least four
years after the date of the final rule. For the reasons described
above, we do not believe this additional time is necessary for this
program. We are finalizing a start date of January 1, 2011, as proposed.
We discuss the lead time for the 1.3 vol% maximum average standard,
which takes effect July 1, 2012 for non-small refiners and importers,
and July 1, 2016 for small refiners, in the next section.
d. Upper Limit Benzene Standard
In the proposal, we discussed the potential concern that without an
upper limit, some refiners may choose to allow their benzene levels to
increase, or to remain unchanged indefinitely. However, we also said
that once an average standard is in place, any increase in benzene
levels will necessarily come at the cost of purchasing additional
credits. We tentatively concluded that this downward pressure on
benzene levels meant there would likely be no increases in benzene from
any refinery, whether or not there was an upper limit. In fact, we
concluded that this pressure would result in actual reductions at
almost all refineries, especially into the future as refiners try to
limit their reliance on credits as much as and whenever it is
economical to do so (see 71 FR 15867-68).
We nonetheless considered the implications of an upper limit on the
actual level of benzene in the gasoline that refiners produce (as
opposed to the level achieved using credits). (See 71 FR 15678-79.) We
considered an upper limit both in the form of a per-gallon benzene cap
and a limit on the average of actual benzene in gasoline produced by a
refinery (``maximum average standard''). Of these two approaches, we
recognized that a per-gallon cap would be the more rigid. If every
batch needed to meet the cap, there would be no opportunity to offset
benzene spikes with lower-benzene production at other times. Even
during times of normal operation, our review of refinery batch data
indicated that unavoidable wide swings commonly occur in the benzene
content of gasoline batches, even for refineries that have relatively
low benzene levels on average. A per-gallon cap could result in
refiners halting gasoline production during short-term shut-downs of
benzene control equipment or in other temporary excursions in benzene
levels. Unless a per-gallon limit were generous enough or included
case-by-case exceptions (eroding the possible benefit of the cap), many
refiners would likely need to implement much deeper and more costly
reductions in benzene than would otherwise be necessary, simply to
protect against such fluctuations. For some refiners, we concluded, a cap
[[Page 8484]]
could make complying with the program prohibitively expensive.
The other option on which we solicited comment, a maximum average
standard, would be more flexible. A maximum average standard would
limit the average benzene content of the actual production at each
refinery over the course of the year, regardless of the extent to which
credits may have been used to comply with the 0.62 vol% average
standard. Thus, a maximum average standard would allow for short-term
benzene fluctuations as long as the annual average benzene level of
actual production was less than that upper limit.
Several commenters stated that an upper limit would add costs
without resulting in additional benefits, and supported a program
without upper limits. Other commenters, however, expressed serious
concerns about the potential consequences of a program without upper
limits. Several commenters were concerned that under the program as
proposed, it would be possible for refiners to maintain benzene levels
well above the standard indefinitely while complying through the use of
credits, thus potentially reducing the benefits of the program where
this gasoline is used. Some commenters noted that under the proposed
program, gasoline in some areas could still have significantly higher
benzene levels than in other parts of the country. These commenters
believe that these projected disparities raise issues of fairness.
While our modeling of the proposed average standard suggested that all
refineries were likely to reduce their benzene levels to some extent
and that there would be significant reductions in gasoline benzene
levels in each PADD, the commenters noted that an upper limit would
provide a guarantee of reduction to at least the level of the upper limit.
After evaluating the results of our updated refinery analysis and
considering all of the comments, we have reconsidered the
appropriateness of an upper limit standard. For the reasons discussed
above, we continue to believe that a per-gallon cap for CG would be
inappropriate for a benzene control program due to actions refineries
would need to take to protect against common fluctuations in benzene
content, and the related adverse cost and energy implications if
refineries invest in deeper benzene reductions or need to temporarily
shut down. In contrast, the per-gallon cap for RFG of 1.3 vol%, which
is currently in place, functions differently than would a per-gallon
cap that applied to both the RFG and CG pools. The per-gallon cap for
RFG alone is appropriate because the CG pool provides an outlet for
batches of higher benzene RFG. However, if such a cap were applied to
CG as well, refiners would be left without an outlet. As we said in the
proposal, any meaningful level for a per-gallon cap applying to CG
would thus overly restrict the normal fluctuations in gasoline benzene
(see 71 FR 15869).
On the other hand, we now believe that the program should include a
maximum average benzene standard, set at an appropriate level. The
maximum average standard has the strong advantage of ensuring that the
benzene content of gasoline produced by each refinery (or imported by
each importer) will average no higher than this standard, regardless of
the use of credits, providing greater assurance that actual in-use
benzene reductions more clearly reflect our modeled projections which
form the basis for this rule. At the same time, the maximum average
standard avoids the serious drawbacks of a per-gallon cap.
Our refinery modeling is state of the art, but it cannot predict
with high confidence each refinery's actions and how benzene trading
will occur in each instance. We have done a refinery-by-refinery
assessment of the most economical decisions we believe the industry
will make to comply with the standard. However, in developing the
model, we did not have access to specific information on many
refineries, much of which is confidential business information. To fill
these gaps, we used broader industry average information for a number
of key model input parameters (including benzene levels in crude oil
and in gasoline blendstocks, individual refinery unit throughput and
operating conditions, distillation ``cut points,'' and future refinery
expansions). Since there is wide variation in these important
parameters among different refineries that impacts their baseline
benzene levels and their opportunities for control, our model's
assumptions inherently vary from actual refinery circumstances.
Furthermore, by necessity, our model assumes that all refineries will,
in effect, work collectively to make the most economical investment
decisions on a nationwide basis, as though each knew in advance the
investment decisions of the others. In reality, each individual
refinery will be making its decisions independently of each other,
based on very limited information about other refineries' actions. In
addition, our model assumes that refiners will limit their actions to
only treat the principal benzene-containing stream (reformate). There
are individual circumstances where it may be economical to also treat
other refinery streams. If the benzene in these other streams is indeed
treated by some refineries, it is possible that sufficient credits
might be generated to allow more refineries to avoid benzene reductions
altogether by simply purchasing credits. Consequently, although our
refinery-by-refinery modeling predicts significant benzene reductions
in all areas nationwide, individual refineries might continue to have
gasoline with higher benzene levels than the model predicts. This may
also result in higher regional variation in gasoline benzene levels
than the model predicts. Thus, we cannot dismiss this possibility with
a high degree of confidence.
For these reasons, we believe that the addition of a maximum
average standard to the 0.62 average standard provides far greater
assurance that refineries will control benzene in the future as
projected--and certainly will not increase benzene levels to be greater
than the level of the maximum average standard. Furthermore, through
selection of an appropriate level for the maximum average standard, we
believe that we are achieving this goal with a minimal impact on the
overall costs of the program.
We did not originally propose a maximum average standard, largely
because of our interpretation of our modeling done for the proposal.
That modeling indicated that adding a maximum average standard would
result in significantly more benzene reduction in some areas, but that
these increases would cause other areas to experience slightly smaller
benzene reductions (see 71 FR 15903). Our updated modeling results are
similar. In the proposal, we considered this potential for smaller
benzene reductions in some areas to be a reason not to propose a
maximum average standard. However, upon further evaluation of these
modeling results, given the level of uncertainty in the model to
predict individual refinery and regional benzene levels (as discussed
above), we do not have confidence in the size of any offsetting
increases in benzene levels in other areas, or even whether they would
occur. In addition, we recognize that some of the refiners that the
model predicts would reduce benzene slightly less (creating the
apparent offsetting regional effects) may in fact decide to overcomply
with the standard in order to maintain a compliance ``safety margin,''
regardless of the presence of a maximum average standard, and
regardless of the strength of the market for the generated credits.
[[Page 8485]]
In light of this, we do not think it warrants giving up the benefits
resulting from the inclusion of the maximum average standard.
Absent concern about any measurable offsetting effects from a
maximum average standard, we believe that the major benefit of such a
standard can and should be pursued. That is, the program can achieve
increased certainty that the significant gasoline benzene reductions
across all parts of the nation that our modeling projects will indeed
occur, and thus that regional variations in gasoline benzene levels
will indeed be minimized as we project.
We believe that setting the maximum average standard at a level of
1.3 vol% accomplishes the goal of reasonably assuring lower benzene
levels for all refineries while balancing the negative aspects of more-
and less-stringent benzene standards. Virtually all the commenters who
supported a maximum average standard agreed that 1.3 vol% would be a
reasonable level for such a standard. EPA agrees. Implementing a
maximum average standard lower than 1.3 vol% would begin to
significantly increase the number of refineries that would need to
install the more expensive benzene reduction equipment. This would
quickly diminish the value of the flexibility provided by the ABT
program and thus force an increasing number of refineries to make
expenditures in benzene control that could otherwise be smaller or
avoided entirely, significantly increasing the overall cost of the
program. Conversely, a maximum average standard greater than 1.3 vol%
would require progressively fewer refineries to take action to reduce
their benzene levels. This would in turn provide less assurance that
actual benzene levels would be broadly achieved. As shown in detail in
Chapter 9 of the RIA, the addition of the 1.3 vol% standard has minimal
impact on the overall costs of the program. It is for this reason that
we find that the 0.62 vol% annual average standard, in tandem with the
1.3 vol% maximum average standard, represents the greatest benzene
reductions achievable considering cost, energy supply, and other
enumerated statutory factors.
We believe that it is very important to monitor levels of benzene
as refiners and importers begin to respond to the average and maximum
average standards. EPA currently collects information on benzene and
several other gasoline parameters for every batch of gasoline produced
in or imported into the U.S., and publishes it in aggregate form on the
EPA Web site. By January 1, 2011, we plan to begin publishing a more
detailed annual report on gasoline quality. We will present this data
on a PADD-by-PADD basis (to the extent that protection of confidential
business information allows). We expect that these reports will be a
valuable tool to stakeholders and members of the public who are
interested in following the real-world progress of this rule's gasoline
benzene reductions.
Among other changes discussed in section VIII below, our updated
refinery-by-refinery model uses year-round 2004 gasoline production
data as a starting point (replacing 2003 summer production data used in
the proposal) and incorporates updated crude oil and benzene prices.
The model thus generates updated predictions of the responses of
refineries to the benzene standards. Our updated analysis shows that
with the 0.62 vol% average standard and the maximum average benzene
standard of 1.3 vol%, benzene levels will be reduced very significantly
in all parts of the country. However, a degree of variation will
continue to exist, due to the wide variety of refinery configurations,
crude oil supplies, and approaches to benzene control, among other
factors. This remaining variation is clearly legally permissible,
notwithstanding the reasonable objective of assuring that reductions
occur both regionally and nationally, because we do not read CAA
section 202(l)(2) as requiring uniform gasoline benzene levels in each
area of the country, since the standard is to be technology-based
considering costs and other factors which vary considerably by region
and by refinery. On the other hand, the maximum average standard will
have the appropriate effect of directionally providing a greater degree
of geographic uniformity of gasoline benzene levels and these levels
remain achievable considering cost and the other enumerated factors.
Reducing gasoline benzene levels on both a national and regional basis
is within the discretion of the Administrator, since section 202(l)(2)
does not specify whether the maximum degree of emission reductions are
to be achieved nationally, regionally, or both.
The 1.3 vol% maximum average standard will become effective 18
months after the 0.62 vol% average standard, on July 1, 2012, and on
July 1, 2016 for small refiners. While there is ample lead time for
non-small refiners to meet the 0.62 vol% standard by January 1, 2011,
we believe that staggering the implementation dates will ensure that
the implementation of the programs by the refining industry is as
smooth and efficient as possible. An important aspect of the design of
this program as proposed is the recognition that not all of the benzene
reduction would occur at once. As discussed in detail in section
VI.A.2.b below, we expect that individual refiners will use the ABT
program to schedule their benzene control expenditures in the most
efficient way, using the early credit and standard credit provisions.
This will essentially create a gradual phasing-in of the reductions in
gasoline benzene content, beginning well before the initial compliance
date of January 1, 2011 and spreading out industry-wide compliance
activities over several years. Since the 1.3 vol% standard may not be
met using credits, we have set the implementation dates for this
standard such that the credit program can continue to be fully utilized
for an additional 18 months after the effective date of the 0.62 vol%
average standard to allow the intended phasing-in of the program to
occur (i.e., there will be 18 additional months during which the 0.62
vol% average standard may be achieved exclusively by using credits).
We acknowledge that by incorporating the 1.3 vol% maximum average
standard into the program, we are creating additional compliance
challenges for a small number of refineries that might have relied on
credits but will now need to install capital equipment to meet the 1.3
vol% maximum average standard. Most refiners will need to take these
steps by July 1, 2012. Small refiners will need to take these steps
four years later, by July 1, 2016. Although we believe that most
(possibly all) refiners will be able to install appropriate benzene
control equipment by these future dates, there may be a small number of
refiners that continue to face significant financial hurdles as these
dates approach. We have considered this concern, and we believe that
the leadtime provided, including the longer leadtime for small
refiners, and the hardship relief provisions discussed below, are
sufficient to address any circumstances of severe economic impacts on
individual refineries. We are making clear that serious economic
difficulties in meeting the 1.3 vol% maximum average standard may be a
basis for granting relief under the ``extreme hardship'' provision
discussed in sectionVI.A.3. below.
2. Description of the Averaging, Banking, and Trading (ABT) Program
a. Overview
We are finalizing a nationwide averaging, banking, and trading
(ABT) program that allows us to set a more
[[Page 8486]]
stringent annual average gasoline benzene standard than would otherwise
be justifiable. The ABT program allows refiners and importers to choose
the most economical compliance strategy (investment in technology,
credits, or both) for meeting the 0.62 vol% annual average benzene
standard. The flexibility afforded by the program is especially
significant and needed given the considerable variation in existing
gasoline benzene levels, which reflects important differences in crude
oil composition and individual refinery design.
From 2007-2010, refiners can generate ``early credits'' by making
qualifying benzene reductions earlier than required. In 2011 and
beyond, refiners and importers can generate ``standard credits'' by
producing/importing gasoline with benzene levels below 0.62 volume
percent (vol%) on an annual average basis. Credits may be used
interchangeably towards compliance with the 0.62 vol% standard,
``banked'' for future use, and/or transferred nationwide to other
refiners/importers subject to the standard. In addition to the 0.62
vol% standard, refiners and importers must also meet a 1.3 vol% maximum
average benzene standard beginning July 1, 2012. To comply with the
maximum average standard, gasoline produced by a refinery or imported
by an importer may not exceed 1.3 vol% on an annual average basis.
While the 1.3 vol% maximum average standard places a limitation on
credit use, we believe that the ABT program still provides the refining
industry with significant compliance flexibility as described below.
b. Credit Generation
i. Eligibility
Under the ABT program, U.S. refiners (including ``small
refiners''\190\) who produce gasoline by processing crude oil and/or
intermediate feedstocks through refinery processing units (see Sec.
80.1270) are eligible to generate both early and standard benzene
credits. Foreign refiners with individual refinery baselines
established under Sec. 80.910(d) who imported gasoline into the U.S.
in 2004-2005 are also eligible to generate early credits. Importers, on
the other hand, are only eligible to generate standard credits under
the ABT program. As explained in the proposal, importers are precluded
from generating early credits because, unlike refineries, they do not
need additional lead time to comply with the standard since they are
not investing in benzene control technology. Additionally, due to their
variable operations, importers could potentially redistribute the
importation of foreign gasoline to generate ``windfall'' early credits
with no associated benzene emission reduction value (see 71 FR 15874).
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\190\ Refiners approved as small refiners under Sec. 80.1340.
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Benzene credits may only be generated on gasoline which is subject
to the benzene requirements as described at Sec. 80.1235. This
excludes California gasoline (gasoline produced or imported for use in
California) but includes gasoline produced by California refineries for
use outside of California. Despite the fact that California gasoline is
not covered by this program, EPA sought comment on whether and how
credits could be generated based on California gasoline benzene
reductions and applied towards non-California gasoline compliance (see
71 FR 15873). We did not receive any substantive comments on this
matter but nonetheless considered the feasibility of such a program
(described in more detail in the Summary and Analysis of Comments). We
concluded that such a program could be very problematic to implement
and, based on the apparent lack of interest by California gasoline
refineries, it is likely that there would be very few participants. As
a result, we have decided to maintain the proposed ABT provision which
excludes California gasoline from generating credits.
ii. Early Credit Generation
To encourage early innovation in gasoline benzene control
technology, refiners are eligible to generate early credits for making
qualifying benzene reductions prior to the start of the program.
Refiners must first establish individual benzene baselines for each
refinery planning on generating early credits (discussed further in
section VI.B.1). Benzene baselines are defined as the annualized
volume-weighted benzene content of gasoline produced at a refinery from
January 1, 2004 through December 31, 2005. To qualify to generate early
credits, refineries must make operational changes and/or improvements
in benzene control technology to reduce gasoline benzene levels in
accordance with Sec. 80.1275. Additionally, a refinery must produce
gasoline with at least ten percent less benzene (on a volume-weighted
annual average basis) than its 2004-2005 baseline. The first early
credit generation period is from June 1, 2007 through December 31,
2007, and subsequent early credit generation periods are the 2008,
2009, and 2010 calendar years (2008 through 2014 calendar years for
small refiners).
We are setting a ten percent reduction trigger point for early
credits to ensure that changes in gasoline benzene levels result from
real refinery process improvements. Without a substantial trigger
point, refiners could earn credits for the normal year-to-year
fluctuations in benzene level at a given refinery allowed under MSAT1.
These windfall credits could negatively impact the ABT program
because--as reflections of normal variability--they would have no
associated benzene emission reduction value. As described in the
proposal, we believe that a percent reduction trigger point, as opposed
to an absolute level or fixed reduction trigger point, is the most
appropriate early credit validation tool considering the wide range in
starting benzene levels. In addition, we believe that ten percent is an
appropriate value for the trigger point because it prevents most
windfall credit generation, yet is not so restrictive as to discourage
refineries from making early benzene reductions (see 71 FR 15875).
Once the ten percent reduction trigger point is met, refineries can
generate credits based on the entire gasoline benzene reduction. For
example, if in 2008 a refinery reduced its annual average benzene level
from a baseline of 2.00 vol% to 1.50 vol% (below the trigger point of
0.90 x 2.00 = 1.80 vol%), its early benzene credits would be determined
based on the difference in annual benzene content (2.00 - 1.50 = 0.50
vol%) divided by 100 and multiplied by the gallons of gasoline produced
in 2008 (expressed in gallons of benzene).
We proposed that refiners be prohibited from moving gasoline or
gasoline blendstock streams from one refinery to another in order to
generate early credits (see 71 FR 15875). We received comments
indicating that many refiners trade blending components between
refineries to maximize gasoline production while minimizing cost, and
that such companies should not be prohibited from generating early
credits. In fact, we are not prohibiting these types of normal refinery
activities, nor are we prohibiting such refineries from participating
in the early credit program. We are simply requiring that all
refineries make real operational changes and/or improvements in benzene
control technology to reduce gasoline benzene levels in order to be
eligible to generate early credits. In most cases, moving gasoline
blendstocks from one refinery to another does not result in a net
benzene reduction (one refinery gets cleaner at the expense of another
[[Page 8487]]
getting dirtier). Accordingly, refineries that lower their benzene
levels exclusively through blendstock trading (no additional qualifying
reductions) are not eligible to generate early credits under the ABT
program. An exception exists for refineries that transfer benzene-rich
reformate streams for processing at other refineries with qualifying
post-treatment capabilities, e.g., extraction or benzene saturation
units. Under this scenario, the transferring refinery would be eligible
to generate early credits because a real operational change to reduce
gasoline benzene levels has been made. The regulations at Sec. 80.1275
have been modified to more clearly reflect our intended early credit
eligibility provisions, and specifically address blendstock trading.
iii. Standard Credit Generation
Refiners and importers may generate standard credits for
overcomplying with the 0.62 vol% gasoline benzene standard on a volume-
weighted annual average basis in 2011 and beyond (2015 and beyond for
small refiners).\191\ For example, if in 2011 a refinery's annual
average benzene level is 0.52, its standard benzene credits would be
determined based on the margin of overcompliance with the standard
(0.62-0.52 = 0.10 vol%) divided by 100 and multiplied by the gallons of
gasoline produced during the 2011 calendar year (expressed in gallons
of benzene). Likewise, if in 2012 the same refinery were to produce the
same amount of gasoline with the same average benzene content, they
would earn the same number of credits. The standard credit generation
opportunities for overcomplying with the standard continue indefinitely
(see 71 FR 15872).
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\191\ Standard credit generation begins in 2011, or 2015 for
small refiners, regardless of whether a refinery pursues early
compliance with the 0.62 vol% standard under Sec. 80.1334.
---------------------------------------------------------------------------
c. Credit Use
As proposed, we are finalizing a program where refiners and
importers can use benzene credits generated or obtained under the ABT
program to meet the 0.62 vol% annual average standard in 2011 and
beyond (2015 and beyond for small refiners). We are also finalizing a
1.3 vol% maximum average standard which takes effect in July 2012 (July
2016 for small refiners). The maximum average standard must be met
based on actual refinery benzene levels, essentially placing a cap on
total credit use. As discussed above in section VI.A.1.d, we believe
this is an appropriate strategy for addressing the current disparity in
gasoline benzene levels throughout the country.
Overall, the ABT program will allow for a more gradual phase-in of
the 0.62 vol% benzene standard and a more cost-effective program. The
early credit program gives refiners an incentive to make initial
gasoline benzene reductions sooner than required. The early credits
generated can be used to provide refiners with additional lead time to
make their final (more expensive) investments in benzene control
technology. As a result, some benzene reductions will occur prior to
the start of the program while others will lag (within the realms of
the credit life provisions described below). We anticipate that there
will be enough early credits generated to allow refiners to postpone
their final investments by up to three years, which coincides with the
maximum time afforded by the early credit life provisions. In addition,
we predict that standard credits generated during the early credit lag
period will allow for an additional 16 months of lead time. The result
is a gradual phase-in of the 0.62 vol% benzene standard beginning in
June 2007 and ending in July 2016, as shown below in Figure VI.A-1.
Without early credits, refineries would be immediately constrained by
the 0.62 vol% standard and likely forced to make their final
investments sooner (including those necessary to meet the 1.3 vol%
maximum average standard).
[[Page 8488]]
[GRAPHIC]
[TIFF OMITTED] TR26FE07.010
In addition to earlier benzene reductions and a more gradual phase-
in of the 0.62/1.3 vol% standards (as shown above), the ABT program
results in a more cost-effective program for the refining industry. Our
modeling shows that allowing refiners to average benzene levels
nationwide to meet the 0.62 vol% standard reduces ongoing compliance
costs by about 50% from 0.51 to 0.27 cents per gallon (refer to RIA
Section 9.6.2). Our modeling further shows that the early credit
program we are finalizing results in the lowest possible compliance
costs during the phase-in period. Without an early credit program, the
total amortized capital and operating costs incurred by the refining
industry during the phase-in period is estimated to be $905 million
(2003 dollars).\192\ With an early credit program, the total cost
incurred during the same phase-in period is reduced to $608 million,
providing about $300 million in savings. In the absence of an ABT
program altogether, the total cost incurred during the phase-in period
would be $1.7 billion. As a result, the ABT program in its entirety
could save the refining industry up to $1.1 billion in compliance costs
from 2007-2015. For a more detailed discussion on compliance costs,
refer to section VIII.A. For more information on how the cost savings
associated with the ABT program were derived, refer to RIA Section
6.5.5.12.
---------------------------------------------------------------------------
\192\ ABT program cost calculations consider future gasoline
growth and the time value of money. The gasoline growth rate from
2004-2012 was estimated by the refinery cost model and future growth
rates were obtained from EIA's AEO 2006. The costs and resulting
cost savings estimated for the phase-in period were calculated based
on compliance costs presented in RIA Section 9.6.2 and adjusted back
to 2007 to account for the time-value of money based on a 7% average
rate of return.
---------------------------------------------------------------------------
Under the ABT program, early and standard benzene credits can be
used interchangeably towards compliance with the 0.62 vol% standard
(within the realms of the credit life provisions described below). Each
credit (expressed in gallons of benzene) can be used on a one-for-one
basis to offset the same volume of benzene produced/imported in
gasoline above the standard. For example, if in 2011 a refinery's
annual average benzene level was 0.72, the number of benzene credits
needed to comply would be determined based on the margin of
undercompliance with the standard (0.72-0.62 = 0.10 vol%) divided by
100 and multiplied by the gallons of gasoline produced during the 2011
calendar year. The credits needed would be expressed in gallons of benzene.
To enable enforcement of the program, the ABT program we are
finalizing includes a limit on credit life (for both early and standard
credits), a limit on the number of times credits may be traded, and a
prohibition on outside parties taking ownership of credits. We believe
that these provisions are necessary to ensure that the full benzene
reduction potential of the program is realized and that the credit
trading program is equitably administered among all participants. In
the proposal, we acknowledged concerns that credit use limitations
might in some circumstances unnecessarily hamper the credit market.
Specifically, we requested comment on ways that some of the provisions
might be reduced or eliminated while still maintaining an enforceable
program (see 71 FR 15872). Although we received many comments on the
proposed ABT program, we did not receive any substantive comments
indicating that the proposed credit provisions would be a significant
burden on refiners or importers. Likewise, we did not receive
[[Page 8489]]
any substantive comments suggesting that the removal of such
restrictions would greatly improve the efficiency of the ABT program.
For these reasons, we are finalizing such provisions for credit use
(described in more detail below).
i. Early Credit Life
Early credits must be used towards compliance within three years of
the start of the program; otherwise they will expire and become
invalid. In other words, early credits generated or obtained under the
ABT program must be applied to the 2011, 2012, or 2013 compliance
years. Similarly, early credits generated/obtained and ultimately used
by small refiners must be applied to the 2015, 2016, or 2017 compliance
years. The result is that no early credits may be used toward
compliance with the 2014 year. This break in the early credit
application period may help funnel surplus early credits facing
expiration to small refiners in need.
ii. Standard Credit Life
Standard credits must be used within five years from the year they
were generated (regardless of when/if they are traded). For example,
standard credits generated in 2011 would have to be applied towards the
2012 through 2016 compliance year(s); otherwise they would expire and
become invalid. To encourage trading to small refiners, there is a
credit life extension for standard credits traded to and ultimately
used by small refiners. These credits may be used towards compliance
for an additional two years, giving standard credits a maximum seven-
year life. For example, the same above-mentioned standard credits
generated in 2011, if traded and used by a small refiner, would have
until 2018 to be applied towards compliance before they would expire.
iii. Consideration of Unlimited Credit Life
Since compliance with the gasoline benzene standards is determined
at the refinery or importer level, there are no enforceable downstream
standards associated with this rulemaking. Thus, it is critical that
EPA be able to conduct enforcement at the refinery or importer level.
Additionally, since EPA enforcement activities are limited by the five-
year statute of limitations in the Clean Air Act, allowing credit life
beyond five years poses serious enforcement issues. As a result, we are
finalizing three-year early credit life and five-year standard credit
life provisions (as just described above). We believe that these credit
life provisions are limited enough to satisfy enforcement and trading
concerns yet sufficiently long to provide necessary program
flexibility. However, we recognize that extending credit life might
result in increased program flexibility. Accordingly, in the proposal,
EPA sought comment on different ways to structure the program that
would allow for unlimited credit life. Specifically, we asked for
comment on how unlimited credit life could be beneficial to the program
and/or how the associated increase in recordkeeping and enforcement
issues could be mitigated (see 71 FR 15872). Comments received provided
no support for why unlimited credit life would improve program
flexibility or how enforcement issues could be addressed. Furthermore,
we did not receive any comments suggesting that the proposed credit
life provisions would significantly hamper trading. As such, we are
finalizing the credit life provisions as proposed.
iv. Credit Trading Provisions
It is possible that benzene credits could be generated by one
party, subsequently transferred or used in good faith by another, and
later found to have been calculated or created improperly or otherwise
determined to be invalid. If this occurs, as in past programs, both the
seller and purchaser will have to adjust their benzene calculations to
reflect the proper credits and either party (or both) could be
determined to be in violation of the standards and other requirements
if the adjusted calculations demonstrate noncompliance with the 0.62
vol% standard.
Credits must be transferred directly from the refiner or importer
generating them to the party using them for compliance purposes. This
ensures that the parties purchasing them are better able to assess the
likelihood that the credits are valid. An exception exists where a
credit generator transfers credits to a refiner or importer who
inadvertently cannot use all the credits. In this case, the credits can
be transferred a second time to another refiner or importer. After the
second trade, the credits must be used or terminated. In the proposal,
we requested comment on whether more than two trades should be
allowed--specifically, whether three or four trades were more
appropriate and/or more beneficial to the program (see 71 FR 15876). We
did not receive any comments providing analytical support for an
additional number of trades. We are finalizing a maximum of two trades,
consistent with other recent rulemakings, in order to provide
flexibility while still maintaining enforceability as discussed in the
proposal.
There are no prohibitions against brokers facilitating the transfer
of credits from one party to another. Any person can act as a credit
broker, regardless of whether such person is a refiner or importer, as
long as the title to the credits is transferred directly from the
generator to the user. This prohibition on outside parties taking
ownership of credits was promulgated in response to problems
encountered during the unleaded gasoline program and has since appeared
in subsequent fuels rulemakings. To reevaluate potential stakeholder
interest in removing this prohibition, EPA sought comment on this
provision in the proposal--specifically, whether there were potential
benefits to allowing other parties to take ownership of credits and how
such a program would be enforced (see 71 FR 15876). We did not receive
any comments on this issue and continue to believe that our proposal is
appropriate. Therefore, to maintain maximum program enforceability and
consistency with all of our other ABT programs for mobile sources and
their fuels, we are maintaining our existing prohibition on outside
parties taking ownership of credits.
We are not imposing any geographic restrictions on credit trading.
Credits may be traded nationwide between refiners or importers as well
as within companies to meet the 0.62 vol% national average benzene
standard. We believe that restricting credit trading could reduce
refiners' incentive to generate credits and hinder trading essential to
this program. In addition, since there are no fuel-availability issues
associated with this rule (as opposed to the case of the ultra-low
sulfur diesel program), there is no need to impose a geographic restriction.
3. Provisions for Small Refiners and Refiners Facing Hardship
Situations
In developing the MSAT2 program, we evaluated the need for and the
ability of refiners to meet the proposed benzene standards as
expeditiously as possible. We continue to believe that it is feasible
and necessary for the vast majority of the program to be implemented in
the time frame stated above to achieve the air quality benefits as soon
as possible. Further, we believe that refineries owned by small
businesses generally face unique hardship circumstances as compared to
larger refiners. We are also finalizing provisions for other refiners
to allow them to seek limited relief from hardship situations on a
case-by-case
[[Page 8490]]
basis. These provisions are discussed in detail below.
a. Provisions for Small Refiners
We proposed several special provisions for refiners that are
approved as small refiners (see VI.A.3.a.ii below). This is due to the
fact that small refiners generally have greater difficulty than larger
companies (including those large companies that own small-capacity
refineries) in raising capital for investing in benzene control
equipment. Small refiners are also likely to have more difficulty in
competing for engineering resources and in completing construction of
the needed benzene control (and any necessary octane recovery)
equipment in time to meet the required standards (see also the more
detailed discussion at 71 FR 15877).
As explained in the discussion of our compliance with the
Regulatory Flexibility Act below in section XII.C and in the Final
Regulatory Flexibility Analysis in Chapter 14 of the RIA, we carefully
considered the impacts of the regulations on small businesses. Most of
our analysis of small business impacts was performed as a part of the
work of the Small Business Advocacy Review Panel (``SBAR Panel'', or
``the Panel'') convened prior to the proposed rule, pursuant to the
Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). (The final report of the
Panel is available in the docket.)
For the SBREFA process, EPA conducted outreach, fact-finding, and
analysis of the potential impacts of our regulations on small
businesses. Based on these factors and analyses by all Panel members,
the Panel concluded that small refiners in general would likely
experience a significant and disproportionate financial hardship in
reaching the objectives of the MSAT2 program. We proposed many of the
provisions recommended by the Panel and we are finalizing these
provisions in this action.
i. Definition of Small Refiner for Purposes of the MSAT2 Small Refiner
Provisions
The criteria to qualify for small refiner status for this program
are in most ways the same as those required in the Gasoline Sulfur and
the Highway and Nonroad Diesel rules. However, there are some
differences; as stated in our more recent fuels programs, we believe
that it is necessary to limit relief to those small entities most
likely to experience adverse economic impacts from fuel regulations. We
are finalizing the following provisions for determining small refiner
status.
To qualify as a small refiner, a refiner must demonstrate that it
meets all of the following criteria: (1) Produced gasoline from crude
during calendar year 2005; (2) had no more than 1,500 employees, based
on the average number of employees for all pay periods from January 1,
2005 to January 1, 2006; and, (3) had an average crude oil capacity
less than or equal to 155,000 barrels per calendar day (bpcd) for 2005.
We are likewise finalizing the provision requiring refiners to apply
for, and for EPA to approve, a refiner's status as a ``small refiner''.
Small refiner provisions are limited to refiners of gasoline from
crude because they are the entities that bear the investment burden and
the consequent economic hardship. Therefore, blenders, importers, and
additive component producers are not eligible. For these same reasons,
small refiner status is limited to those refiners that owned and
operated the refinery during the period from January 1, 2005 through
December 31, 2005. This is consistent with the approach taken in the
Nonroad Diesel rule, but we are revising the text to be more clear on
this issue.
In determining its crude oil capacity and total number of
employees, a refiner must include the crude oil capacity and number of
employees of any subsidiary companies, any parent companies, any
subsidiaries of the parent companies, and any joint venture partners.
As stated in the proposal, there was confusion in past rules regarding
ownership. Thus, we proposed defining a parent company as any company
(or companies) with controlling ownership interest, and a subsidiary of
a company as any company in which the refiner or its parent(s) has a
controlling ownership interest (see 71 FR 15878). We requested comment
on these clarifications in the proposal, but did not receive any
comments on these aspects of the small refiner definition. Therefore,
we are finalizing the definition of parent company and related
clarifying provisions such that the employees and crude capacity of all
parent companies, and all subsidiaries of all parent companies, must be
taken into consideration when evaluating compliance with these criteria.
We received comments regarding the small refiner employee count and
crude capacity criteria. These commenters stated that they believed
that EPA's criteria fail to provide relief to a small number of
refiners whom they believe are similar in many respects to those
refiners that will qualify as small under our criteria. The commenters
pointed to recent Congressionally enacted programs, specifically the
Energy Policy Act of 2005 (EPAct) and the American Jobs Creation Act of
2004 (Jobs Act), which use definitions that are different from the SBA
definition, and from the criteria EPA is adopting in this rule. The
EPAct focuses on refinery size rather than company size, and the Jobs
Act focuses on refinery-only employees rather than employees company-
wide. EPA has established the criteria for qualifying for small refiner
relief based on the Small Business Administration's (SBA) small
business definition (per 13 CFR 121.201).
We do not believe that it would be appropriate to change the
proposed small refiner employee count or crude capacity limit criteria
to fit the definitions used in either of the two recent statutes. While
Congress is able to establish special provisions for subsets of the
industry in programs like those mentioned above, EPA appropriately
focuses, under SBREFA and in this rulemaking, on consideration of
relief on those refining companies that we believe are likely to face
serious economic hardship as a result of compliance with the rule.
Under programs subject to the EPAct and Jobs Act definitions, relief
would be granted to refineries that are owned by larger companies, or
companies that have additional sources of revenue (indicated by more
employees and/or refining capacity), and also refineries owned by
foreign governments. These definitions do not focus as directly on
refiners which, due to their size, could incur serious adverse economic
impact from fuel regulations; and EPA consequently is not adopting
either of them in this rule. Further, SBA established its small
business definition to set apart those companies which are most likely
to be at an inherent economic disadvantage relative to larger
businesses. We agree with the assessment that refiners of this size may
be afforded special consideration under regulatory programs that have a
significant economic impact on them (insofar as is consistent with
Clean Air Act requirements). We continue to believe that it is most
appropriate to remain consistent with our previous fuels programs and
retain the criteria to qualify for small refiner status that have been
used in the past (with some minor clarifications to avoid confusion),
since these criteria best identify the class of small refiner which may
incur disproportionate regulatory impact under the rule. We are therefore
finalizing the small refiner qualification criteria that were proposed.
As previously stated, our intent has been, and continues to be,
limiting the small refiner relief provisions to the
[[Page 8491]]
small subset of refiners that are likely to be seriously economically
challenged as a result of the new regulations. We assume that new
owners that purchase a refinery after December 31, 2005 do so with full
knowledge of the proposed regulation. Given that they have the
resources available to purchase the refinery assets, they are not in an
economic hardship situation. Therefore, they should include compliance
planning as part of their purchase decision. Similar to earlier fuel
rules, we are finalizing a provision that a refiner that restarts a
refinery in the future is eligible for small refiner status. In such
cases, we will judge eligibility under the employment and crude oil
capacity criteria based on the most recent 12 consecutive months before
the application, unless we conclude from data provided by the refiner
that another period of time is more appropriate. However, unlike past
fuel rules, this will be limited to a company that owned the refinery
at the time that it was shut down. New purchasers will not be eligible
for small refiner status for the reasons described above. Companies
with refineries built after January 1, 2005 will also not be eligible
for the small refiner hardship provisions, again for the reasons given
above.
Similar to previous fuel sulfur programs, we also proposed that
refiners owned and controlled by an Alaska Regional or Village
Corporation organized under the Alaska Native Claims Settlement Act are
also eligible for small refiner status, based only on the refiner's
employee count and crude oil capacity (see 71 FR 15878). We did not
receive any comments on this provision, and we are finalizing it in
this action.
ii. Small Refiner Status Application Requirements
A refiner applying for status as a small refiner under this program
is required to apply and provide EPA with several types of information
by December 31, 2007. (The application requirements are summarized in
section VI.B.2, below.) A refiner seeking small refiner status under
this program must apply for small refiner status, regardless of whether
the refiner had been approved or rejected for small refiner status
under another fuel program. As with applications for relief under other
rules, applications for small refiner status under this rule that are
later found to contain false or inaccurate information will be void ab
initio.
iii. Small Refiner Provisions
Delay in the Effective Date of the Standards
We proposed that small refiners be allowed to postpone compliance
with the 0.62 vol% benzene standard until January 1, 2015, four years
after the general program would begin (see 71 FR 15878). At such time,
approved small refiners would be required to meet the 0.62 vol% benzene
standard. As stated in the proposal, this additional lead time is
justified because small refiners face disproportionate challenges,
which the additional lead time will help to mitigate. We requested
comment on this proposed provision, and we received many comments
supporting it and none opposing it.
Normally a period of two to three years of lead time is required
for a refiner to secure necessary financing and to carry out capital
improvements for benzene control (see VI.A.1.c.i. above). Commenters
specifically noted that additional lead time would allow small refiners
to more efficiently obtain financing and contracts to carry out
necessary capital projects (or to obtain credits) with less direct
competition with non-small refiners for financing and for contractors
to carry out capital improvements. Some commenters noted that they
generally supported the proposed program of a 0.62 vol% benzene
standard with no upper limit and the proposed small refiner relief.
While we did not propose an upper limit, as discussed above in section
VI.A.1, we have chosen to finalize a 1.3 vol% refinery maximum average.
The additional lead time also allows EPA to make programmatic
adjustments, if necessary, before small refiners are required to comply
with the benzene standards. As discussed below, we are finalizing a
requirement that EPA review the program in 2012, leaving a number of
years to adjust the program before small refiners are required to meet
the benzene standards. The additional lead time for small refiners will
also provide these refiners with three years of lead time following the
review to take the review results into account in completing capital
projects if necessary or desirable to meet the benzene standards. Based
on these assessments, we are therefore finalizing a four-year period of
additional lead time for small refiners for compliance with the 0.62
vol% benzene standard, until January 1, 2015 (and small refiners would
continue to meet the requirements of MSAT1 until January 1, 2015).
Further, we are finalizing an additional 4 years of lead time for small
refiners to comply with the 1.3 vol% maximum average benzene standard,
until July 1, 2016.
Early ABT Credit Generation Opportunities
During the development of the proposal, we anticipated that many
small refiners would likely find it more economical to purchase credits
for compliance than to comply by making capital investments to reduce
gasoline benzene. However, some small refiners indicated that they
would make reductions to their gasoline benzene levels to fully or
partially meet the proposed 0.62 vol% benzene standard. Therefore, we
proposed that small refiners that take steps to meet the benzene
requirement before January 1, 2015 would be eligible to generate early
credits (see 71 FR 15879). Current and previous fuels programs allow
for credit generation opportunities to encourage early compliance, and
extending this opportunity to small refiners, based on the small
refiner effective date, is consistent with this objective. Small
refiners generally supported this provision and we did not receive any
adverse comments on it.
Early credit generation opportunities will provide more credits for
the MSAT2 ABT program and will help to achieve the air quality goals of
the MSAT2 program earlier than otherwise required. We are therefore
finalizing an early credit generation provision for small refiners.
This is similar to the general early credit generation provision that
is provided to all refiners, except that small refiners may generate
early credits until January 1, 2015. As discussed in section
VI.A.2.b.ii above, refineries must reduce their 2004-2005 benzene
levels by at least ten percent to generate early credits. This ten
percent threshold is being set to ensure that changes in gasoline
benzene levels result from real refinery process improvements, not just
normal fluctuations in benzene levels at a given refinery (allowed
under MSAT1). The small refiner early credit generation period will be
from June 1, 2007 to December 31, 2014, after which standard credits
may be generated indefinitely for those that overcomply with the 0.62
vol% annual average standard.
Extended Credit Life
During the SBREFA process, many small refiners expressed interest
in relying upon credits as an ongoing compliance strategy for meeting
the 0.62 vol% gasoline benzene standard. However, several small
refiners voiced concerns surrounding the idea of relying on the credit
market to avoid large
[[Page 8492]]
capital costs for benzene control. One of their primary concerns was
that credits might not be available and/or traded to small refiners in
need. To increase the certainty that credits would be available, we
proposed a two-year credit life extension for credits generated by or
traded to small refiners (see 71 FR 15879). Not only does this
provision encourage trading to small refiners, it creates a viable
outlet for credits facing expiration. Most small refiners supported the
proposed credit life provision. However, one refiner suggested that we
finalize unlimited credit life for credits traded to small refiners.
Although unlimited credit life could have some perceived benefits,
overall it poses serious enforcement problems. Therefore, for the
reasons described above in VI.A.2.c.iii, we are not finalizing
unlimited credit life for credits traded to small refiners. Further, we
are finalizing a slightly modified version of the proposed small
refiner extended credit life provision to better reflect its intended
purpose. First, the two-year credit life extension pertains only to
standard credits. The extension does not apply to early credits because
refiners already have an incentive to trade early credits to small
refiners. Based on the nature of the early credit life program (three-
year life based on the start of the program) and small refiners'
delayed program start date (2015 as opposed to 2011), early credits
traded to small refiners are already valid for an additional four
years. Second, the two-year credit life extension applies only to
standard credits traded to small refiners. There is no need to extend
credit life for credits generated by small refiners, because in this
event, the small refiner would already have the utmost certainty that
the credits would be available for use.
ABT Program Review
We proposed that we would perform a review of the ABT program (and
thus, the small refiner flexibility options) by 2012, one year after
the general program begins (see 71 FR 15879). Coupled with the small
refiner four-year additional lead time provision, the ABT program
review after the first year of the overall program will provide small
refiners with roughly three years, after learning the results of the
review, to obtain financing and perform engineering and construction.
We are committing to this provision today. The review will take into
account the number of early credits generated industry-wide each year
prior to the start of the MSAT2 program, as well as the number of
credits generated and transferred during the first year of the overall
benzene control program. In part to support this review, we are
requiring that refiners submit pre-compliance reports, similar to those
required under the highway and nonroad diesel programs. In addition,
the first compliance report that refiners submit (for the 2011
compliance period) will provide important information on how many
credits are actually being generated or utilized during the first year
of the program.
The ABT pre-compliance reports will be due annually on June 1 from
2008 through 2011. The reports must include projections of how many
credits will be generated and how many credits will need to be used at
each refinery. The reports must also contain information on a refiner's
plans (for each refinery) for compliance with the benzene standard,
including whether or not the refiner will utilize credits alone to
comply with the standard. Refiners must also report any early credits
that may have been transferred to another entity prior to January 1,
2011 and the sale price of those credits.
In addition, ABT compliance reports will be due annually beginning
February 28, 2012. For any refiner expecting to participate in the
credit trading program (under Sec. 80.1275 and/or Sec. 80.1290, the
report must include information on actual credit generation and usage.
Refiners must also provide any updated information regarding plans for
compliance. EPA will publish the results of these refinery compliance
reports and the results of our review as soon as possible to provide
small refiners with information on the ABT program roughly three years
prior to the small refiner compliance date. EPA will maintain the
confidentiality of information from individual refiners submitted in the
reports. We will present generalized summaries of the reports annually.
If, following the review, EPA finds that the credit market is not
adequate to support the small refiner provisions, we will revisit the
provisions to determine whether or not they should be altered or
whether EPA can assist the credit market (and small refiners' access to
credits). For example, the Panel suggested that EPA could consider
actions such as: (1) The ``creation'' of credits by EPA that would be
introduced into the credit market to ensure that there are additional
credits available for small refiners; (2) a requirement that a
percentage of all credits to be sold be set aside and only made
available for small refiners; and (3) a requirement that credits sold,
or a certain percentage of credits sold, be made available to small
refiners before they are allowed to be sold to any other refiners.
Further, we are finalizing an additional hardship provision to
assist small refiners. This hardship provision would be for the case of
a small refiner for which compliance with the 0.62 vol% benzene
standard would be feasible only through the purchase of credits, but
for whom purchase of credits is not economically feasible. This
hardship provision will only be available following the ABT program
review, since EPA wishes to use the most accurate information to assess
credit availability and the working of the credit market. The provision
will only be afforded to a small refiner on a case-by-case basis, and
must be based on a showing by the refiner of the practical or economic
difficulty in acquiring credits for compliance with the 0.62 vol%
benzene standard (or some other type of similar situation that would
render its compliance with the standard not economically feasible). The
relief offered under this hardship provision is a further delay, on an
individual refinery basis, for up to two years. Applications for relief
under this provision must meet the requirements set out in Sec.
80.1343. Following the two years, a small refiner will be allowed to
request one or more extensions of the hardship until the refinery's
material situation has changed. Finally, if a small refiner is unable
to comply with the 1.3 vol% refinery maximum average, it may apply for
relief from this standard under the general hardship provisions
discussed below in section VI.A.3.b. Applications for relief from the
1.3 vol% refinery maximum average must be received by January 1, 2013
and must meet the requirements set out in Sec. 80.1335.
iv. The Effect of Financial and Other Transactions on Small Refiner
Status and Small Refiner Relief Provisions
We believe that the effects of financial (and other) transactions
are also relevant to this action. We proposed these provisions (see 71
FR 15880) and did not receive any comments on them. We continue to
believe that these provisions are appropriate and are finalizing the
provisions discussed below.
Large Refiner Purchasing a Small Refiner's Refinery
One situation involves a ``non-small'' refiner that wishes to
purchase a refinery owned by an approved small refiner. The small
refiner may not have completed or even begun any necessary planning to
meet the MSAT2 standards, since it would likely have planned to make
use of the special small refiner
[[Page 8493]]
relief provisions. We assume that the refiner would have incorporated
financial planning for compliance into its purchase decision. However,
we recognize that a limited amount of time would be required for the
physical completion of the refinery upgrades for compliance. (This
situation would be similar to that addressed in the Nonroad Diesel
program (96 FR 39051).)
We therefore believe that an appropriate period of lead time for
compliance with the MSAT2 requirements is warranted where a refiner
purchases any refinery owned by a small refiner, whether by purchase of
a refinery or purchase of the small refiner entity. A refiner that
acquires a refinery from an approved small refiner will be provided
with 30 additional months from the date of the completion of the
purchase transaction (or until the end of the applicable small refiner
relief interim period if it is within 30 months). During this 30-month
period, production at the newly-acquired refinery may remain at the
benzene levels that applied to that refinery for the previous small
refiner owner, and all existing small refiner provisions and
restrictions will also remain in place for that refinery. At the end of
this period, the refiner must comply with the ``non-small refiner''
standards. There will not be an adverse environmental impact of this
provision, since the small refiner would already have been provided
relief prior to the purchase and this provision would be no more generous.
We expect that in most (if not all) cases, the 30 months of
additional lead time will be sufficient for the new refiner-owner to
accomplish the necessary planning and any needed refinery upgrades. If
a refiner nonetheless believes that the technical characteristics of
its plans would require additional lead time, the refiner may apply for
additional time and EPA will consider such requests on a case-by-case
basis. Based on information provided in such an application and other
relevant information, EPA will decide whether additional time is
technically necessary and, if so, how much additional time would be
appropriate. As discussed above, in no case will compliance dates be
extended beyond the time frame of the applicable small refiner relief.
Small Refiner Losing Its Small Refiner Status Due To Merger or Acquisition
Another type of potential transaction involves a refiner with
approved small refiner status that later loses its small refiner status
because it no longer meets the small refiner criteria. An approved
small refiner that exceeds the small refiner employee or crude capacity
limit due to merger or acquisition will lose its small refiner status.
This includes exceedances of the employee or crude capacity criteria
caused by acquisitions of assets such as plants and equipment, as well
as acquisitions of business entities.
Our intent has been, and continues to be, to limit the small
refiner relief provisions to a small subset of refiners that are most
likely to be significantly economically challenged, as discussed above.
At the same time, it is also our intent to avoid stifling normal
business growth. Therefore, under this program, a refiner will be
disqualified from small refiner status if it exceeds the small refiner
criteria through its involvement in transactions such as being acquired
by or merging with another entity, through the small refiner itself
purchasing another entity or assets from another entity, or when it
ceases to process crude oil. However, if a small refiner grows through
normal business practices, and exceeds the employee or crude capacity
criteria without merger or acquisition, it will retain its small
refiner status for this program.
In the sole case of a merger between two approved MSAT2 small
refiners, both small refiners will be allowed to retain their small
refiner status under this program. As in past fuel rulemakings, we
believe the justification for continued small refiner relief for each
of the merged entities remains valid. Small refiner status for the two
entities of the merger will not be affected, and hence the original
compliance plans of the two refiners should not be impacted. Moreover,
no environmental detriment will result from the two small refiners
maintaining their small refiner status within the merged entity as they
would have likely maintained their small refiner status had the merger
not occurred. We did not receive any comments on this provision.
We recognize that a small refiner that loses its small refiner
status because of a merger with, or acquisition of, a non-small refiner
would face the same type of technical lead time concerns discussed
above for a non-small refiner acquiring a small refiner's refinery.
Therefore, we are also providing the 30 months of additional lead time
described above for non-small refiners purchasing a small refiner's
refinery.
b. Provisions for Refiners Facing Hardship Situations
The MSAT2 program includes a nationwide credit trading program of
indefinite duration for the 0.62 vol% annual average benzene standard,
and we expect that credits will be available at a reasonable cost
industry-wide. However, as explained in the proposal (71 FR 15880-
15881), there could be circumstances when refiners would need hardship
relief. We reiterate this conclusion here, especially given the 1.3
vol% refinery maximum average benzene standard in the final rule. These
hardship provisions are available to all refiners, small and non-small,
with relief being available on a case-by-case basis following a showing
of certain requirements (as described in the regulations at sections
80.1335 and 80.1336). We believe that the inclusion of hardship
provisions for refiners is a necessary part of adopting the benzene
requirements as the maximum reduction achievable considering costs.
Without a mechanism to consider economic hardship to particular
refineries, the overall level of the standards would need to be higher
to reflect the potential increased costs. Note, however, that we do not
intend for these hardship waiver provisions to encourage refiners to
delay planning and investments they would otherwise make.
We are finalizing two forms of hardship relief: the first applies
to situations of extreme and unusual hardship, and the second applies
to situations where unforeseen circumstances prevent the refiner from
meeting the benzene standards. These provisions are similar to the
hardship provisions that were proposed, but with some modification
because this final rule includes a 1.3 vol% refinery maximum average
benzene standard, which cannot be satisfied through the use of credits.
While we sought comment in the proposal on such a standard, we did not
propose it, and therefore also did not propose any hardship relief
specific to it.
As discussed further below, the application requirements and
potential relief available differ somewhat depending upon whether a
refiner applies for hardship relief for the 0.62 vol% benzene standard,
the 1.3 vol% refinery maximum average, or both (a refiner may apply for
relief from both standards, but EPA will address them independently).
This is partly due to the fact that a refiner may use credits to meet
the 0.62 vol% benzene standard, but credits cannot be used for
compliance with the 1.3 vol% refinery maximum average standard. EPA can
impose appropriate conditions on any hardship relief. Note also that
any hardship relief granted under this rule will be separate and apart
from EPA's authority under the Energy Policy Act to issue temporary
waivers for extreme and unusual supply circumstances, under amended
section 211(c)(4). In general,
[[Page 8494]]
commenters stated that they supported the inclusion of hardship
provisions, but they did not provide any specific comments regarding
these provisions.
i. Temporary Waivers Based on Extreme Hardship Circumstances
We are finalizing the proposed hardship relief provisions based on
a showing of extreme hardship circumstances, with some slight
modifications from the proposed extreme hardship relief provision (see
71 FR 15881). We did not receive comment on the proposed hardship
provision.
Extreme hardship circumstances could exist based on severe economic
or physical lead time limitations of the refinery to comply with the
benzene standards required by the program. Such extreme hardship may be
due to an inability to physically comply in the time available, an
inability to secure sufficient financing to comply in the time
available, or an inability to comply in the time available in a manner
that would not place the refiner at an extreme competitive disadvantage
sufficient to cause extreme economic hardship. A refiner seeking such
hardship relief under this provision will have to demonstrate that
these criteria were met. In addition to showing that unusual
circumstances exist that impose extreme hardship in meeting the benzene
standards, the refiner must show: (1) Circumstances exist that impose
extreme hardship and significantly affect the ability to comply with
the gasoline benzene standards by the applicable date(s); and (2) that
it has made best efforts to comply with the requirements. Refiners
seeking additional time must apply for hardship relief, and the
hardship applications must contain the information required under Sec.
80.1335.
For relief from the 0.62 vol% benzene standard in extreme hardship
circumstances, an aspect of the demonstration of best efforts to comply
is that severe economic or physical lead time limitations exist and
that the refinery has attempted, but was unable, to procure sufficient
credits. EPA will determine an appropriate extended deficit carry-
forward time period based on the nature and degree of the hardship, as
presented by the refiner in its hardship application, and on our
assessment of the credit market at that time. Moreover, because we
expect the credit program to be operating and robust, we believe that
circumstances under which we would grant relief from the 0.62 vol%
benzene standard will be rare, and should we grant relief, it would
likely be for less than three years. Further, we may impose additional
conditions to ensure that the refiner was making best efforts to comply
with the benzene standards while offsetting any loss of emission
control from the program (due to extended deficit carry-forward).
For relief from the 1.3 vol% refinery maximum average benzene
standard in extreme hardship circumstances, a refiner must show that it
could not meet the 1.3 vol% standard, despite its best efforts, in the
timeframe required due to extreme economic or technical problems.
Extreme hardship relief from the 1.3 vol% refinery maximum average
standard is available for both non-small and small refiners. This
provision is intended to address unusual circumstances that should be
apparent now, or well before the standard takes effect. Thus, refiners
must apply for such relief by January 1, 2008, or January 1, 2013 for
small refiners. If granted, such hardship relief would consist of
additional time to comply with the 1.3 vol% refinery maximum average.
The length of such relief and any conditions on that relief will be
granted on a case-by-case basis, following an assessment of the
refiner's hardship application, but could be for a longer period than
for relief from the 0.62 vol% standard since credits cannot be used for
compliance with the 1.3 vol% refinery maximum average.
ii. Temporary Waivers Based on Unforeseen Circumstances
We are also finalizing the proposed temporary hardship provision
based on unforeseen circumstances, which, at our discretion, will
permit any refiner or importer to seek temporary relief from the
benzene standards under certain rare circumstances (see 71 FR 15880).
This waiver provision is similar to provisions in prior fuel
regulations. It is intended to provide refiners and importers relief in
unanticipated circumstances--such as a refinery fire or a natural
disaster--that cannot be reasonably foreseen now or in the near future.
We did not receive comments on this proposed hardship provision.
To receive hardship relief based on unforeseen circumstances, a
refiner or importer will be required to show that: (1) The waiver is in
the public interest; (2) the refiner/importer was not able to avoid the
noncompliance; (3) the refiner/importer will meet the benzene standard
as expeditiously as possible; (4) the refiner/importer will make up the
air quality detriment associated with the nonconforming gasoline, where
practicable; and (5) the refiner/importer will pay to the U.S. Treasury
an amount equal to the economic benefit of the noncompliance less the
amount expended to make up the air quality detriment. These conditions
are similar to those in the RFG, Tier 2 gasoline sulfur, and the
highway and nonroad diesel regulations, and are necessary and
appropriate to ensure that any waivers that are granted will be limited
in scope. Such a request must be based on the refiner or importer's
inability to produce compliant gasoline at the affected facility due to
extreme and unusual circumstances outside the refiner or importer's
control that could not have been avoided through the exercise of due
diligence.
For relief from the 0.62 vol% benzene standard based on unforeseen
circumstances, the hardship request must also show that other avenues
for mitigating the problem, such as the purchase of credits toward
compliance under the credit provisions, had been pursued and yet were
insufficient or unavailable. Hardship relief from that standard will
allow a deficit to be carried forward for an extended, but limited,
time period (more than the one year allowed by the rule). The refiner
or importer must demonstrate that the magnitude of the impact was so
severe as to require such an extension. EPA will determine an
appropriate extended deficit carry-forward time period based on the
nature and degree of the hardship, as presented by the refiner or
importer in its hardship application, and on our assessment of the
credit market at that time.
For relief from the 1.3 vol% refinery maximum average benzene
standard based on unforeseen circumstances, the hardship request must
show that, despite its best efforts, the refiner or importer cannot
meet the standard in the timeframe required. Relief will be granted on
a case-by-case basis, following an assessment of the refiner's hardship
application.
c. Option for Early Compliance in Certain Circumstances
We are finalizing an option that would allow a refinery to begin
compliance with the MSAT2 benzene standards earlier than 2011 instead
of maintaining compliance with its MSAT1 baseline. See 71 FR 15881 for
the proposal's discussion of this option.\193\ We are providing this
option because refineries that meet the criteria discussed below are
already providing the market with very clean gasoline from a mobile
source air toxics
[[Page 8495]]
perspective. In the proposal, we took comment on such an option,
stating that eligibility for this option would be limited to those that
have historically better than average toxics performance, lower than
average benzene and sulfur levels, and a significant volume of gasoline
impacted by the phase-out of MTBE use. However, in order to qualify for
this option, a refinery must produce gasoline by processing crude and
other intermediate feedstocks and not merely be a blender or importer
of gasoline, as discussed later.
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\193\ The 1.3 vol% maximum average standard was not discussed in
the proposal vis-a-vis this early compliance option. However, any
refinery approved for this option should easily meet the 1.3 vol% standard.
---------------------------------------------------------------------------
A refinery that is approved for this option would comply with the
0.62 vol% annual average and 1.3 vol% maximum average benzene standards
and would not be required to continue to comply with its applicable
toxics performance requirements, i.e., its MSAT1 baseline and its anti-
dumping or RFG toxics performance standards. We believe this option is
appropriate because if qualifying refineries had to continue to comply
with MSAT1 \194\ until 2011, they would likely be forced to reduce
gasoline output in order to comply, while other refineries or
importers, most likely with less clean MSAT1 baselines, would provide
the replacement gasoline. The result would be less supply of these
refineries' cleaner gasoline and more supply of fuel with higher toxics
emissions, leading to a net detrimental effect on overall MSAT
emissions in the surrounding region.
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\194\ While refineries are subject to MSAT1 and anti-dumping or
RFG toxics performance requirements depending on the gasoline type
(CG and/or RFG) they produce, in almost all cases, the MSAT1
standard is more stringent than the corresponding anti-dumping or
RFG toxics standard.
---------------------------------------------------------------------------
We chose 2003 as the period for determining eligibility for this
option because State MTBE bans began taking effect in 2004. Refiners
who had used MTBE generally now use ethanol as the replacement source
for oxygen. Although RFG no longer has an oxygen requirement \195\,
MSAT1 baselines were established when that requirement was still in
place. Even some CG producers used significant amounts of MTBE as
reflected in their MSAT1 baselines. Ethanol provides less toxics
reduction benefits than MTBE, and so the refinery must take other
actions in order to continue to meet its MSAT1 standard. Consequently,
while MSAT1 baseline adjustments in the past were limited to RFG, it
may be possible for a refinery to also qualify to adopt MSAT2 early for
its CG pool. Both qualification and the ability to adopt MSAT2 are
allowed separately for RFG and CG. For example, a refinery that
qualifies to adopt MSAT2 early for RFG will be permitted to do so for
RFG alone while maintaining its MSAT1 baseline for its CG, or vice versa.
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\195\ 71 FR 26691, May 8, 2006.
---------------------------------------------------------------------------
As mentioned in the proposal, the criteria for eligibility for
early compliance are similar in concept to those EPA has used in
granting refinery-specific adjustments to MSAT1 baselines, that is,
significantly cleaner than the national average for toxics, benzene,
and sulfur, and relatively high MTBE use. We re-evaluated those
criteria to determine the numerical criteria that a refinery would have
to meet in order to qualify for this option. Specifically, a refinery
must at minimum meet the following criteria:
--2003 annual average benzene level less than or equal to 0.62 vol%
--2003 annual average MTBE use greater than 6.0 vol%
--2003 annual average sulfur level less than 140 ppm
--MSAT1 RFG baseline greater than 30.0% reduction or CG less than 80
mg/mile
Many refineries can reduce benzene and sulfur levels to reduce
toxics emissions. However, those that used a significant amount of MTBE
and already have low benzene and sulfur levels also have fairly
stringent toxics emissions performance standards. As a result, they may
have little ability to further reduce sulfur or benzene or make other
refinery changes to offset the impact of switching from MTBE to
ethanol. Refineries that are not in this situation are not so
constrained. We believe that the criteria above are an appropriate
screening to delineate between these two groups.
To qualify for this provision we believe it is appropriate for a
refinery to have used at least 6.0 vol% MTBE in their gasoline in their
2003 baseline; when the oxygen provided by this amount of MTBE is
provided instead by ethanol, a substantial loss in toxics performance
results. A benzene average of less than or equal to the 0.62 vol%
standard is appropriate because if a refinery's average benzene is
higher, they would have to further reduce benzene to comply with the
MSAT2 standard early. However, to qualify for this provision to switch
to MSAT2 early, a refinery should have no viable options for reducing
benzene further to continue to meet their MSAT1 baseline. We chose the
140 ppm sulfur level because we found that even for refineries with
significant MTBE use (in the 6-13 vol% range), the sulfur reductions
brought about by the Tier 2 gasoline sulfur standard provided
sufficient benefit to offset much of the increase in toxics emissions
that results from eliminating MTBE and replacing it with ethanol.
Finally, refineries should have had MSAT1 baseline toxics performance
significantly cleaner than the average in order to qualify. The MSAT1
baseline toxics performance thresholds listed above were set based on
past experience with baseline adjustments where we found that only
those with significantly clean baselines (in addition to low benzene,
low sulfur, and high MTBE use) would have to reduce production in order
to comply with their MSAT1 standard in the face of MTBE bans. Thus, we
are limiting this provision to those with relatively clean baselines as
our goal is preventing the perverse outcome that refineries with
cleaner gasoline may be forced to reduce their production volume only
to have it be made up by refineries with dirtier baselines. The
threshold helps ensure that only those refineries in situations where
such an outcome could realistically have otherwise occurred are
permitted to exercise this option. Refineries that do not fulfill all
of the threshold requirements may have to take further refinery
processing-related actions to meet their MSAT1 baseline, but are
unlikely to have to reduce production and/or have that production
replaced by someone with a less clean standard.
In addition to meeting the screening criteria mentioned, a refinery
would still have to apply to EPA to use this compliance option and
would need to demonstrate that it cannot further reduce its benzene or
sulfur levels, nor make other refinery processing changes in order to
maintain compliance with its MSAT1 baseline due to the impact of
switching from MTBE to ethanol. Details of the application requirements
and approval process are provided in section 80.1334 of the
regulations. We estimate that less than 10 refineries may meet the
screening criteria and thus potentially qualify for this option based
on our analysis of their 2003 data and MSAT1 baselines. Note that this
early compliance option will apply only to the type of gasoline that
qualifies--RFG or CG--not to the refinery's total pool. In 2011, the
MSAT2 benzene standards will apply to the refinery's total applicable
gasoline pool.
We are limiting this compliance option to refineries that produce
gasoline by processing crude and intermediate feedstocks through
refinery processing equipment. Thus, this option is not available to
gasoline blenders and importers. While gasoline blenders and importers
may have gasoline with significantly cleaner than average toxics
[[Page 8496]]
performance, benzene and sulfur levels, and may have used large amounts
of MTBE, they have more options in the marketplace for obtaining
qualifying gasoline and gasoline blending components. Refineries have
comparatively less ability to adjust their refining operations, without
significantly reducing volume, in order to accommodate the change from
MTBE to ethanol.
Few comments were received regarding this provision. All commenters
supported the provision. Many of those suggested that it be available
to any refinery. We continue to believe that this provision should
apply only to those entities that meet the criteria above. Those that
do not meet the criteria have the ability to further adjust their
benzene and sulfur content values to be able to comply with their MSAT1
baselines. If this provision was available to all refineries, it could
result in an overall nationwide backsliding on MSAT1. The intent of
this provision is to provide appropriate relief to a limited number of
entities that have unique challenges, while at the same time ensuring
that the net result is cleaner gasoline in the marketplace than would
otherwise be there.
EPA also took comment on when entities that are approved for this
option should be allowed to begin compliance with the MSAT2 benzene
standards. We received comment supporting allowing such compliance for
the entire calendar year 2007, even though the rule will not be final
until partway into that year. Other suggested options include the next
calendar year, and partial year compliance for 2007. This latter option
would likely be unworkable under MSAT1 due to differences between
summer and winter MSAT performance. Thus, we decided that refineries
that are approved for this option will be allowed to comply with the
MSAT2 benzene standard for the entire 2007 period. We have also decided
against requiring approved refineries to wait until the 2008 compliance
period because we want to ensure that gasoline production from these
refineries is maximized, and waiting until 2008 would not achieve that
goal. Because this is an optional program for those that qualify,
approved refiners may choose to comply with MSAT2 beginning in 2007, or
beginning in 2008.
As a final note on this subject, we also proposed that refineries
that meet the criteria and are approved for early compliance with the
MSAT2 benzene standards would not be allowed to generate early benzene
credits (see 71 FR 15881). A few commenters thought that such
refineries should be allowed to generate early credits. However, the
criteria for generating early credits require that the refinery reduce
benzene by 10% below its 2004-2005 baseline benzene level. The early
compliance provision is predicated on the fact that an approved
refinery has almost no ability to reduce benzene in order to maintain
compliance with its MSAT1 baseline. If such a refinery were able to
further reduce benzene, it would negate its need for early compliance
with the MSAT2 benzene standard. Therefore, we are finalizing this
early compliance option with this limitation as proposed.
B. How Will the Gasoline Benzene Standard Be Implemented?
This section summarizes the main implementation provisions in the
regulations and provides additional clarification in a few cases.
1. General Provisions
Compliance with the 0.62 vol% annual average and 1.3 vol% maximum
average benzene standards is determined over a refiner's or importer's
total gasoline pool, RFG and conventional gasoline (CG) combined. For
the 0.62 vol% standard, the first annual compliance period for non-
small refiners and for importers is 2011. For the 1.3 vol% standard,
the first compliance period for these entities is July 1, 2012 through
December 31, 2013. Thereafter, compliance is determined annually. Small
refiners will comply with the 0.62 vol% on an annual basis beginning in
2015. Compliance with the 1.3 vol% maximum average standard commences
for small refiners on July 1, 2016. For small refiners, the first
compliance period for the 1.3 vol% standard is July 1, 2016 through
December 31, 2017. Thereafter, compliance is determined annually.
Compliance with the benzene standards is achieved separately for
each refinery of a refiner.\196\ For an importer, compliance is
achieved over its total volume of imports, regardless of point of
entry. As discussed in the proposal, gasoline produced by a foreign
refiner is included in the compliance calculation of the importer of
that gasoline, with certain exceptions for early credit generation and
small foreign refiners.
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\196\ Aggregation of facilities for compliance is not allowed
under this benzene control program. However, as pointed out in the
proposal, the ABT program's credit generation and transfer provisions
provide compliance flexibility similar to that provided by aggregation.
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Finished gasoline and gasoline blendstock that becomes finished
gasoline solely upon the addition of oxygenate are included in the
compliance determination. Gasoline produced for use in California is
not included. Gasoline produced for use in the American territories--
Guam, Northern Mariana Islands, American Samoa--is not subject to the
benzene standard. Gasoline produced for use in these areas is currently
exempt from the MSAT1 standards, and for the same reasons we discussed
in the MSAT1 final rule \197\, including distance from gasoline
producers, low gasoline use, and distinct environmental conditions, we
are exempting gasoline produced for these areas from this rule.
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\197\ 66 FR 17253, March 29, 2001.
---------------------------------------------------------------------------
Oxygenate and butane blenders are not subject to the benzene
standard unless they add other gasoline blending components beyond
oxygenates and butane. Similarly, transmix processors are not subject
to the benzene standard. We proposed that transmix processors would be
subject to the benzene standard if they add gasoline blending
components to the gasoline produced from transmix (see 71 FR 15891).
One commenter suggested that only the blending component added to the
gasoline produced from transmix should be subject to the standard
because the transmix processor has no control over the benzene level in
the gasoline produced from transmix, and the benzene in the gasoline
produced from transmix would have already been accounted for by another
entity. We agree with this comment, and have modified the final rule
accordingly.
As discussed earlier, this benzene program has both an early credit
generation period and a standard credit generation period that begins
when the program takes effect. Early credits may be generated from
January 1, 2007 through December 31, 2010 by refineries with approved
benzene baselines. For small refiners, early credit generation extends
through December 31, 2014 for their refineries with approved benzene
baselines. Benzene baselines are based on a refinery's 2004-2005
average benzene content, and refiners can begin applying for benzene
baselines as early as March 1, 2007. Although there is no single cut-
off date for applying for a baseline, refiners planning to generate
early credits must submit individual refinery baseline applications at
least 60 days prior to beginning credit generation at that refinery.
As explained earlier, in order to generate early credits, a
refinery's annual average benzene level must be at least 10 percent
lower than its baseline benzene level, and the refinery must show that
its low benzene levels result, in part, from operational changes and/
[[Page 8497]]
or improvements in benzene control technology since the baseline
period. Foreign refiners who sent gasoline to the U.S. during 2004-2005
under their foreign refiner baseline may generate early credits if they
are able to establish a benzene baseline and agree to comply with other
requirements that help to ensure enforcement of the regulation at the
foreign refinery. Early credits generated or obtained under the ABT
program must be used towards compliance within three years of the start
of the program; otherwise they will expire and become invalid. In other
words, early credits must be applied to the 2011, 2012, or 2013
compliance years. In the case of small refiners, early credits must be
applied to the 2015, 2016, or 2017 compliance years.
Standard credits may be generated by refiners and importers
beginning with the 2011 compliance period. Standard credits may be
generated by small refiners beginning with the 2015 compliance period.
For refiners, credits are generated on a refinery-by-refinery basis for
each facility. For importers, credits are generated over the total
volume imported, regardless of point of entry. Foreign refiners are not
allowed to generate standard credits because compliance for their
gasoline is the responsibility of the importer. In order to generate
standard credits, a refinery's or importer's annual average benzene
level must be less than 0.62 vol%. Standard credits are valid for five
years from the year they were generated. A credit life extension exists
for standard credits traded to and ultimately used by small refiners.
These credits may be used towards compliance for an additional two
years, giving standard credits a maximum seven-year life.
Compliance with the 0.62 vol% standard is based on the annual
average benzene content of the refinery's or importer's gasoline
production or importation, any credits used, and any compliance deficit
carried forward from the previous year. Credits may be used in any
quantity and combination (i.e., early or standard credits) to achieve
compliance with the 0.62 vol% benzene standard beginning with the first
compliance period in 2011, or 2015 for approved small refiners. For the
2011 and 2012 compliance periods, credits may be used in any amount,
and from any starting average benzene level. For example, if the
refinery's annual average benzene level at the end of 2011 is 1.89
vol%, it may use credits to meet the 0.62 vol% standard for that
compliance period. If its average benzene level at the end of 2012 is
1.45 vol%, it may likewise use credits to meet the 0.62 vol% standard
for that period.
The first averaging period for the 1.3 vol% standard for non-small
refiners and importers begins July 1, 2012 and ends December 31, 2013,
an 18-month period. Similarly, the first averaging period for the 1.3
vol% standard for small refiners begins July 1, 2016 and ends December
31, 2017. Credits may not be used to achieve compliance with the 1.3
vol% standard at any time. A refinery must make capital improvements
and/or operational or blending practice changes such that it achieves
an actual average benzene level of no greater than 1.3 vol% for the
initial (18-month) compliance period, and each annual compliance period
thereafter. (An importer must bring in gasoline with benzene levels
that will average to 1.3 vol% or less during these same compliance
periods.) Continuing from our previous example, if at the end of 2012,
the refinery's average benzene level is 1.45 vol%, no further action is
yet needed to meet the 1.3 vol% standard. However, the refinery must
make capital improvements and/or operational or blending practice
changes such that it achieves an actual average benzene level of no
greater than 1.3 vol% for the 18-month period July 1, 2012-December 31,
2013. We will assume for this example that the refinery has a 1.0 vol%
average benzene level at the end of 2013. The refinery can then use
credits to meet the 0.62 vol% standard.
Lack of compliance with the 0.62 vol% standard creates a deficit
that may be carried over to the next year's compliance determination.
Lack of compliance with the 0.62 vol% standard could occur for a number
of reasons, for example, a refinery or importer may choose not to use
(buy) sufficient offsetting credits. However, in the next year, the
refinery or importer must make up the deficit (through credit use and/
or refining or import improvements) and be in compliance with the 0.62
vol% standard.\198\ There is no deficit carry-forward provision
associated with the 1.3 vol% standard. If a refinery or importer is out
of compliance with the 1.3 vol% standard, it is subject to enforcement
action immediately.
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\198\ An extension of the period of deficit carryover may be
allowed in certain hardship situations, as discussed in section A.3.
---------------------------------------------------------------------------
2. Small Refiner Status Application Requirements
A refiner applying for status as a small refiner under this program
is required to apply to and to provide EPA with several types of
information by December 31, 2007. The application requirements are
summarized below. A refiner seeking small refiner status under this
program would need to apply to EPA for that status, regardless of
whether or not the refiner had been approved for small refiner status
under another fuel program. As with applications for relief under other
rules, applications for small refiner status under this rule that are
later found to contain false or inaccurate information would be void ab
initio. Requirements for small refiner status applications include:
--The total crude oil capacity as reported to the Energy Information
Administration (EIA) of the U.S. Department of Energy (DOE) for the
most recent 12 months of operation. This would include the capacity of
all refineries controlled by a refiner and by all subsidiaries and
parent companies and their subsidiaries. We will presume that the
information submitted to EIA is correct. In cases where a company
disagreed with this information, the company could petition EPA with
appropriate data to correct the record when the company submitted its
application for small refiner status. EPA could accept such alternate
data at its discretion.
--The name and address of each location where employees worked from
January 1, 2005 through December 31, 2005; and the average number of
employees at each location during this time period. This must include
the employees of the refiner and all subsidiaries and parent companies
and their subsidiaries.
--In the case of a refiner who reactivated a refinery that was shutdown
or non-operational between January 1, 2005, and January 1, 2006, the
name and address of each location where employees worked since the
refiner reactivated the refinery and the average number of employees at
each location for each calendar year since the refiner reactivated the
refinery.
--The type of business activities carried out at each location.
--The small refiner option(s) the refiner intends to use for each
refinery.
--Contact information for a corporate contact person, including: name,
mailing address, phone and fax numbers, e-mail address.
--A letter signed by the president, chief operating officer, or chief
executive officer of the company (or a designee) stating that the
information contained in the application was true to the best of his/
her knowledge and that the company owned the refinery as of January 1,
2007.
[[Page 8498]]
3. Administrative and Enforcement Provisions
Most of the administrative and enforcement provisions are similar
to those in effect for other gasoline programs, as discussed in the
proposal. The discussion below highlights those areas that we wish to
clarify and those that received significant comment.
a. Sampling/Testing
Because compliance with this program and with the gasoline sulfur
program will become the compliance mechanism for certain RFG and anti-
dumping requirements, some reporting simplifications will occur, as
described below. However, sampling, testing, and reporting of all of
the current fuel parameters will continue to be required. It is
important to continue to monitor how refiners continue to achieve the
toxics control required of RFG and CG through fuel composition changes,
and how other toxics emissions may be affected by this MSAT2 benzene
rule. Continued collection of all of the fuel parameters will
facilitate future toxics evaluation activities.
We proposed to require every-batch sampling for CG under this
program, but indicated that results would not have to be available
before the batch leaves the refinery (see 71 FR 15893). RFG already is
every-batch tested, and the results must be available before the batch
leaves the refinery because of RFG's 1.3 vol% per gallon cap. Several
commenters stated that every-batch testing for CG was unnecessary
because the benzene standard is an average standard, and that it would
be costly, especially for small refiners. These commenters requested
that continued composite sampling be allowed for conventional
gasoline.\199\ Nevertheless, we are concerned about potential
downstream benzene addition. Requiring every-batch testing for CG will
allow for closer monitoring of the movement of high benzene streams. In
this program, we are relying on there being no significant incentive to
dump benzene-rich streams into gasoline downstream of the refinery
where the benzene levels are originally measured. With every-batch
benzene testing of all gasoline, we will be able to better discern if
high benzene batches originated at the refinery, or downstream. With
composite testing, it would be significantly more difficult to
determine the source of the high benzene streams. Thus, we are
finalizing every-batch benzene testing for all gasoline.
---------------------------------------------------------------------------
\199\ Section 80.101(i).
---------------------------------------------------------------------------
b. Recordkeeping/Reporting
This program will require some new records to be kept, such as the
benzene baseline, credits generated, and credit transactions, and new
reports to be filed (e.g., benzene pre-compliance reports). However,
because the current regulations for RFG and anti-dumping toxics
controls and MSAT1 controls are being removed, certain recordkeeping
and reporting requirements will be reduced or eliminated, as detailed
in the regulations. Because the program will not be fully implemented
until small refiners are also subject to both the 0.62 vol% and the 1.3
vol% benzene standards, the process of streamlining the reporting forms
will not be complete until that time.
As mentioned above, in order to provide an early indication of the
credit market for refiners and importers planning on relying upon
benzene credits as a compliance strategy in 2011 and beyond, we are
requiring refiners to submit pre-compliance reports to us in the years
leading up to start of the program. Pre-compliance reporting has proven
to be an indispensable mechanism in implementing the gasoline and
diesel sulfur programs, and we expect this to be the case in this
program as well. Refiners are required to submit annual pre-compliance
reports on June 1st of every year beginning in 2008 and continuing
through 2011 (2015 for small refiners). The pre-compliance reports must
contain engineering and construction plans as well as actual/projected
gasoline production levels, actual/projected gasoline benzene levels,
and actual/projected credit generation and use.
Several commenters suggested that the RFG NOX retail
survey be discontinued after 2006, and that the RFG toxics retail
survey be discontinued after 2010. The surveys use fuel parameters of
RFG sampled from retail stations to estimate VOC, NOX, and
toxics emissions. There are also fuel benzene and oxygen content
surveys. If a survey is ``failed'', gasoline sent to the area must meet
a more stringent standard. Because we are finalizing, as proposed,
provisions that make the gasoline sulfur program the sole regulatory
mechanism used to implement gasoline NOX requirements, and
the benzene control program the sole regulatory mechanism used to
implement the toxics requirements of RFG \200\ and anti-dumping, we
agree that the NOX and toxics surveys are no longer needed.
A discussion of the origin of the survey program, and how the toxics
and NOX requirements for CG and RFG will be met under the
MSAT2 program is provided in Chapter 6.13 of the RIA for this rulemaking.
---------------------------------------------------------------------------
\200\ The 1.3 vol% per gallon cap on RFG benzene remains.
---------------------------------------------------------------------------
C. How Will the Program Relate to Other Fuel-Related Toxics Programs?
In the proposal we presented an analysis that examined
quantitatively how the fuel performance under the new gasoline content
standard and vehicle emissions standard as proposed would compare to
current toxics performance requirements and to performance as modified
by the Energy Policy Act of 2005. This analysis suggested that the fuel
standard alone would exceed previous performance for RFG, and
significantly exceed it for CG.
We have updated the results of this analysis, using better
estimates of future ethanol use developed for the RFS final rulemaking,
as well as the updated benzene projections from the refinery-by-
refinery analysis done for this final rulemaking. As shown in Table
VI.C-1, these updated analyses continue to support the conclusion that
the MSAT2 fuel program will provide greater toxics reductions for both
CG and RFG.
Table VI.C-1.--Estimated Annual Average Total Toxics Performance of Light Duty Vehicles in mg/mi Under Current
and Projected Scenarios.a
----------------------------------------------------------------------------------------------------------------
RFG by PADD CG by PADD
Regulatory scenario Fleet -----------------------------------------------------------------------
year I II III I II III IV V
----------------------------------------------------------------------------------------------------------------
MSAT1 Baseline \b\ (1998-2000). 2002 112 129 97 114 145 107 145 156
EPAct Baseline \b\ (RFG: 2001- 2002 104 121 87 114 145 107 145 156
2002).........................
EPAct Baseline, 2011 \c\....... 2011 67 78 52 62 83 54 82 88
MSAT2 program, 2011 \c\ (Fuel 2011 66 76 52 60 77 52 74 81
standard only)................
[[Page 8499]]
MSAT2 program, 2011 \c\ (Fuel + 2011 64 72 48 56 74 47 70 78
vehicle standards)............
MSAT2 program, 2025 \c\ (Fuel + 2025 39 45 31 36 45 31 44 48
vehicle standards)............
----------------------------------------------------------------------------------------------------------------
\a\ Total toxics performance for this analysis includes overall emissions of 1,3-butadiene, acetaldehyde,
acrolein, benzene and formaldehyde as calculated by MOBILE6.2. Although POM appears in the Complex Model, it
is not included here. However, it contributes a small and relatively constant mass to the total toxics figure
(~4%), and therefore doesn't make a significant difference in the comparisons. Toxics performance figures here
are for representative cities in each PADD, and therefore some geographical variation is not captured here.
\b\ Baseline figures generated in this analysis were calculated differently from the regulatory baselines
determined as part of the MSAT1 program, and are only intended to be a point of comparison for future year
cases.
\c\ Future year scenarios include (in addition to the MSAT2 standards, where stated) effects of the Tier 2
vehicle and gasoline sulfur standards, and vehicle fleet turnover with time, as well as estimated effects of
the renewable fuels standard and the phase-out of ether blending as developed in the RFS rulemaking.
D. How Does This Program Satisfy the Statutory Requirements of Clean
Air Act Section 202(l)(2)?
As discussed earlier in this section, we have concluded that the
most effective and appropriate program for MSAT emission reduction from
gasoline is a benzene control program. We are finalizing, as proposed,
an average benzene content standard of 0.62 vol% along with a
specially-designed ABT program, as well as a maximum average annual
standard of 1.3 vol%. In sections VI.A.1.c and d above, we summarize
our evaluation of the feasibility of the program, and in section VIII.A
we summarize our evaluation of the costs of the program. The analyses
supporting our conclusions in these sections are discussed in detail in
Chapters 6 and 9 of the RIA.
Taking all of this information into account, we believe that a more
stringent program would not be achievable, taking costs into
consideration. As we have discussed, making the 0.62 vol% standard more
stringent would require more refiners to install the more expensive
benzene control equipment, with very little incremental decrease in
benzene emissions. Also, we have shown that refinery costs increase
very rapidly as the level of the average standard is made more
stringent, especially for certain individual technologically-challenged
refineries. We discuss the costs of this program in detail in section
VIII.A of this preamble and in Chapter 9 of the RIA. Moreover, the 0.62
vol% standard achieves significant reductions in benzene levels
nationwide, and achieves significant reductions in each PADD. The 1.3
vol% annual average standard makes it more certain that the predicted
emission reductions will in fact occur.
Conversely, we believe that a less stringent national average
standard than 0.62 vol% would not satisfy our statutory obligation to
promulgate the most stringent standard achievable considering cost and
other factors along with technological feasibility. Furthermore, as
discussed in section VI.A, less stringent standards would not
accomplish several important programmatic objectives, such as avoiding
the triggering of the provisions in the 2005 EPAct to adjust the MSAT1
baseline for RFG. We have also considered energy implications of the
proposed program, as well as noise and safety, and we believe that the
MSAT2 program will have very little impact on any of these factors
(although, as explained in section VI.A above, some of the alternative
toxic control strategies urged by commenters could have adverse energy
supply implications). Analyses supporting these conclusions are also
found in Chapter 9 of the RIA. We carefully considered lead time in
establishing the stringency and timing of the proposed program (see
section VI.A above).
We have carefully reviewed the technological feasibility (see
section VI.A.1.c.i above and chapter 6 of the RIA) and costs of this
program. Based on the considerations outlined in this section VI, we
conclude that this program meets the requirements of section 202(l)(2)
of the Clean Air Act, reflecting ``the greatest degree of emission
reduction achievable through the application of technology which is
available, taking into consideration * * * the availability and costs
of the technology, and noise, energy, and safety factors, and lead time.''
VII. Portable Fuel Containers
As described in this section, we are adopting new HC emissions
standards for portable gasoline containers (gas cans) essentially as
proposed. We are also finalizing the same requirements for portable
diesel and kerosene containers, containers which could easily be used
for gasoline. Manufacturers must begin meeting the new requirements on
January 1, 2009. These new emissions control requirements will reduce
HC emissions from uncontrolled gasoline containers by about 75%,
including reducing spillage losses. The final rule also includes new
certification and compliance requirements that will help ensure that
the containers achieve emissions control in use over the life of the
container. The standards and program requirements we are finalizing are
very similar to those adopted by California in 2005, so that
manufacturers will be able to sell 50-state products. Overall,
commenters were very supportive of the proposed new emissions control
program for portable fuel containers.
We are establishing the portable fuel container (PFC) standards and
emissions control requirements under section 183(e) of the Clean Air
Act, which directs EPA to study, list, and regulate consumer and
commercial products that are significant sources of VOC emissions. In
1995, after conducting a study and submitting a Report to Congress on
VOC emissions from consumer and commercial products, EPA published an
initial list of product categories to be regulated under section
183(e). Based on criteria that we established pursuant to section
183(e)(2)(B), we listed for regulation those consumer and commercial
products that we considered at the time to be significant contributors
to the ozone nonattainment problem, but we did not include PFC
emissions.\201\ After analyzing the emissions inventory impacts of
these containers, we published a Federal Register notice that added
PFCs to the list of consumer
[[Page 8500]]
products to be regulated.\202\ We requested comment on the data
underlying the listing but did not receive any comments.\203\ We
continue to believe that the standards we proposed and are finalizing
for fuel containers represent ``best available controls'' as required
by section 183(e)(3)(A). Determination of the ``best available
controls'' requires EPA to determine the degree of reduction achievable
through use of the most effective control measures (which includes
chemical reformulation, and other measures) after considering
technological and economic feasibility, as well as health, energy, and
environmental impacts.\204\
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\201\ 60 FR 15264 ``Consumer and Commercial Products: Schedule
for Regulation,'' March 23, 1995.
\202\ 71 FR 28320 ``Consumer and Commercial Products: Schedule
for Regulation,'' May 16, 2006.
\203\ See not only the notice cited in the previous note, but
also 71 FR 15894 (``EPA will afford interested persons the
opportunity to comment on the data underlying the listing before
taking final action on today's proposal'').
\204\ See section 183(e)(1); see also section 183(e)(4)
providing broad authority to include ``systems of regulation'' in
controlling VOC emissions from consumer products.
---------------------------------------------------------------------------
A. What Are the New HC Emissions Standards for PFCs?
1. Description of Emissions Standard
We are finalizing as proposed a performance-based standard of 0.3
grams per gallon per day (g/gal/day) of HC to control evaporative and
permeation losses. The standard will be measured based on the emissions
from the container over a diurnal test cycle. The cans will be tested
as a system with their spouts attached. Manufacturers will test the
containers by placing them in an environmental chamber which simulates
summertime ambient temperature conditions and cycling the containers
through the 24-hour temperature profile (72-96 [deg]F), as discussed
below. The test procedures, which are described in more detail below,
ensure that containers meet the emissions standard over a range of in-
use conditions such as different temperatures, different fuels, and
taking into consideration factors affecting durability. EPA received
only supportive comments on the proposed emissions standards.
2. Determination of Best Available Control
We continue to believe that the 0.3 g/gal/day emissions standard
and associated test procedures reflect the performance of the best
available control technologies including durable permeation barriers,
auto-closing spouts, and a can that is well-sealed to reduce
evaporative losses. The standard is both economically and
technologically feasible. To comply with California's program, gas can
manufacturers have developed gas cans with low VOC emissions at a
reasonable cost (see section XIII. for costs). Testing of cans designed
to meet CARB standards has shown the new standards to be
technologically feasible. When tested over cycles very similar to those
we are adopting, emissions from these cans have been in the range of
0.2-0.3 g/gal/day.\205\ These cans have been produced with permeation
barriers representing a high level of control (over 90 percent
reductions) and with auto-closing spouts, which are technologies that
represent best available controls for gas cans. Establishing the
standard at 0.3 g/gal/day will require the use of best available
technologies. As discussed in the proposal, we are finalizing a level
at the upper end of the tested performance range to account for product
performance variability (see 71 FR 15896). In addition, we believe that
current best designs can achieve these levels, so we do not believe
that the standard forecloses use of any of the existing performing
product designs. Our detailed feasibility analysis is provided in the
Regulatory Impact Analysis. We did not receive any comments on our
feasibility analysis.
---------------------------------------------------------------------------
\205\ ``Quantification of Permeation and Evaporative Emissions
From Portable Fuel Container'', California Air Resources Board, June 2004.
---------------------------------------------------------------------------
In addition to considering technological and economic feasibility,
section 183(e)(1)(A) requires us to consider ``health, environmental,
and energy impacts'' in assessing best available controls.
Environmental and health impacts are discussed in section III.
Moreover, control of spillage from containers may reduce fire hazards
as well because cans would stay tightly closed if tipped over. We
expect the energy impacts of gas can control to be positive, because
the standards will reduce evaporative fuel losses.
3. Diesel, Kerosene and Utility Containers
Diesel and kerosene containers are manufactured by the same
manufacturers as are gasoline containers and are identical to gasoline
containers except for color (diesel containers are yellow and kerosene
containers are blue). In the proposal, we requested comment on applying
the emissions control requirements being proposed for gasoline
containers to diesel and kerosene containers (see 71 FR 15897).
California included diesel and kerosene cans in their regulations
largely due to the concern that they would be purchased as substitutes
for gasoline containers. We received only supportive comments for
including these containers in the program. Several states and state
organizations urged EPA to include these containers in the EPA program,
viewing their omission as a significant difference between the
California program and EPA's proposed program.
We recognize that using uncontrolled diesel and kerosene containers
as a substitute for gasoline containers would result in a loss of
emissions reductions. California collected limited survey data which
indicated that about 60 percent of kerosene containers were being used
for gasoline. In addition, keeping gasoline in containers marked for
other fuels could lead to misfueling of equipment and possible safety
issues. Finally, not including these containers would likely be viewed
as a gap in EPA's program, resulting in states adopting or retaining
their own emissions control program for PFCs. This would hamper the
ability of manufacturers to have a 50-state product line. For these
reasons, we are including diesel and kerosene containers in the program.
We are also clarifying that utility jugs are considered portable
gasoline containers and therefore are subject to the program. They are
designed and marketed for use with gasoline, often to fuel recreational
equipment such as all-terrain vehicles and personal watercraft. This
interpretation is consistent with the scope of the California program.
California recently issued a clarification that these containers are
covered by their program, after some utility jug manufacturers failed
to meet the existing California requirements.
4. Automatic Shut-Off
We received a few comments encouraging EPA to consider or evaluate
spillage control requirements. California's original program which
began in 2001 required automatic shut-off as a way to reduce spillage.
However, for reasons discussed in the proposal, we did not propose and
are not finalizing automatic shut-off requirements (see 71 FR 15896).
Automatic shut-off is supposed to stop the flow of fuel when the fuel
reaches the top of the receiving tank in order to prevent over-filling.
However, due to a wide variety of receiving fuel tank designs, the auto
shut-off spouts do not work well with a variety of equipment types. In
California, this problem led to spillage and consumer dissatisfaction,
and California has removed automatic shut-off requirements from their
program.
[[Page 8501]]
We continue to believe that including an automatic shut-off
requirement would be counterproductive at this time. We believe that
the automatic closing cans, even without automatic shut-off
requirements, will lead to reduced spillage. Consumers will be able to
watch the fuel rise in the receiving tank and stop fuel flow using the
automatic close features prior to overfill. As discussed in the
proposal, automatic closure keeps the cans closed when they are not in
use and provides more control to the consumer during use. We believe
consumers will appreciate this feature and see it as an improvement
over existing cans, whereas an automatic shut-off that worked with only
some equipment types would not be acceptable.
B. Timing of Standard
We are finalizing as proposed a start date for the new PFC
standards of January 1, 2009. We received comments from state
organizations recommending that the program start on January 1, 2008.
In the proposal we recognized that adequate lead time is a key aspect
of the standard's technological feasibility. Manufacturers have
developed the primary technologies to reduce emissions from gas cans
but will need a few years of lead time to certify products and ramp up
production to a national scale. The certification process will take at
least six months due to the required durability demonstrations
described below, and manufacturers will need time to procure and
install the tooling needed to produce gas cans with permeation barriers
for nationwide sales. Commenters did not provide any new information to
counter these points and we continue to believe for these reasons that
the January 1, 2009 start date is appropriate.
The standards apply to containers manufactured on or after the
start date of the program and do not affect cans produced before the
start date. As proposed, as of July 1, 2009, manufacturers and
importers must not enter into U.S. commerce any products not meeting
the emissions standards. This provides manufacturers with a 6-month
period to clear any stocks of containers manufactured prior to the
January 1, 2009 start of the program, allowing the normal sell-through
of these cans to the retail level. Retailers may sell their stocks of
containers through the course of normal business without restriction.
Containers are required by this rule to be stamped with their
production date (consistent with current industry practices), which
will allow EPA to determine which cans are required to meet the new
standards. We did not receive any comments on these aspects of the
proposal or comments suggesting that the proposed lead times would not
be adequate.
C. What Test Procedures Would Be Used?
As proposed, we are finalizing a system of regulations for
containers that includes test conditions designed to assure that the
intended emission reductions occur over a range of in-use conditions
such as operating at different temperatures, with different fuels, and
considering factors affecting durability. These test procedures are
authorized under section 183(e)(4) as part of a system of regulations
to achieve the appropriate level of emissions reductions. Emission
testing on all containers that manufacturers produce is not feasible
due to the high annual production volumes and the cost and time
involved with emissions testing. Instead, before the containers are
introduced into commerce, the manufacturer will need to receive a
certificate of conformity from EPA that the containers conform to the
emissions standards, based on manufacturers' applications for
certification. Manufacturers must submit test data on a sample of
containers that are prototypes of the products the manufacturer intends
to produce. The certificate issued by EPA will cover the range of
production containers represented by the prototype container. As part
of the application for certification, manufacturers also need to
declare that their production cans will not deviate in materials or
design from the prototype cans that are tested. If the production
containers do deviate, then they will not be coved by the certificate
and it will be a violation of the regulations to introduce such
uncertified containers into commerce. Manufacturers must obtain their
certification from EPA prior to introducing their products into
commerce. The test procedures and certification requirements are
described in detail below. Unless otherwise noted below, we did not
receive comments on these test procedures.
We are requiring that manufacturers test cans in their most likely
storage configuration. The key to reducing evaporative losses from
gasoline containers is to ensure that there are no openings on the cans
that could be left open by the consumer. Traditional cans have vent
caps and spout caps that are easily lost or left off cans, which leads
to very high evaporative emissions. We expect manufacturers to meet the
evaporative standards by using automatic closing spouts and by removing
other openings that consumers could leave open. However, if
manufacturers choose to design cans with an opening that does not close
automatically, we are requiring that containers be tested in their open
condition. If the containers have any openings that consumers could
leave open (for example, vents with caps), these openings thus would
need to be left open during testing. This applies to any opening other
than where the spout attaches to the can. We believe it is important to
take this approach because these openings could be a significant source
of in-use emissions and there is a realistic possibility that these
openings would be inadvertently left open in use.
Except for pressure cycling, discussed below, spouts would be in
place during testing because this would be the most likely storage
configuration for the emissions compliant cans. Spouts would still be
removable so that consumers would be able to refill the cans, but we
would expect the containers to be resealed by consumers after being
refilled in order to prevent spillage during transport. We do not
believe that consumers would routinely leave spouts off cans because
spouts are integral to the cans' use and it is obvious that they need
to be sealed.
1. Diurnal Test
We are finalizing as proposed a test procedure for diurnal
emissions testing where the containers are placed in an environmental
chamber or a Sealed Housing for Evaporative Determination (SHED), the
temperature is varied over a prescribed temperature and time profile,
and the hydrocarbons escaping from the can are measured. Containers are
to be tested over the same 72-96 [deg]F (22.2-35.6 [deg]C) temperature
profile used for automotive applications. This temperature profile
represents a hot summer day when ground level ozone emissions would be
highest. Three containers must be tested, each over a three-day test.
Testing three cans for certification will help address variability in
products or test measurements. All three cans must individually meet
the standard. As noted above, cans must be tested in their most likely
storage configuration.
The final results are to be reported in grams per gallon, where the
grams are the mass of hydrocarbons escaping from the container over 24
hours and the gallons are the nominal can capacity. The daily emissions
will then be averaged for each can to demonstrate compliance with the
standard. This test captures hydrocarbons lost through permeation and
any other evaporative
[[Page 8502]]
losses from the container as a whole. The grams of hydrocarbons lost
may be determined by either weighing the gas can before and after the
diurnal test cycle or measuring emissions directly using the SHED
instrumentation.
Consistent with the automotive test procedures, we are requiring
that the testing take place using 9 pounds per square inch (psi) Reid
Vapor Pressure (RVP) certification gasoline, which is the same fuel
required by EPA to be used in its other evaporative test programs. We
are requiring testing be done using E10 fuel (10% ethanol blended with
the gasoline described above) to help ensure in-use emission reductions
on ethanol-gasoline blends, which tend to have increased evaporative
emissions with certain permeation barrier materials. We continue to
believe that including ethanol in the test fuel will lead to the
selection of materials by manufacturers that are consistent with ``best
available control'' requirements for all likely contained gasolines,
and is clearly appropriate given the expected increase over time of the
use of ethanol blends of gasoline under the renewable fuel provisions
of the Energy Policy Act of 2005.
Diurnal emissions are not only a function of temperature and fuel
volatility, but of the size of the vapor space in the container as
well. We are finalizing as proposed that the fill level at the start of
the test be 50% of the nominal capacity of the can. This would likely
be the average fuel level of the gas can in-use. Nominal capacity of
the cans is defined as the volume of fuel, specified by the
manufacturer, to which the can could be filled when sitting on level
ground. The vapor space that normally occurs in a container, even when
``full,'' would not be considered in the nominal capacity of the can.
All of these test requirements are meant to represent typical in-use
storage conditions for containers, on which EPA can base its emissions
standards. The above provisions for diurnal testing are included as a
way to implement the standards effectively, which, in conjunction with
the new emissions standard, will lead to the use of best available
technology at a reasonable cost. We did not receive comment on these
test procedures.
Before testing for certification, the container must be run through
the durability tests described below. Within 8 hours of the end of the
soak period contained in the durability cycle, the cans are to be
drained and refilled to 50 percent nominal capacity with fresh fuel,
and then the spouts re-attached. When the can is drained, it must be
immediately refilled to prevent it from drying out. The timing of these
steps is needed to ensure that the stabilized permeation emissions
levels are retained. The can will then be weighed and placed in the
environmental chamber for the diurnal test. After each diurnal, the can
must be re-weighed. In lieu of weighing the container, manufacturers
may opt to measure emissions from the SHED directly. For any in-use
testing of containers, the durability procedures will not be run prior
to testing.
California's test procedures are very similar to those described
above. However, the California procedure contains a more severe
temperature profile of 65-105 [deg]F. As proposed, we will allow
manufacturers to use this temperature profile to test cans as long as
other parts of the EPA test procedures are followed, including the
durability provisions below.
2. Preconditioning to Ensure Durable In-Use Control
a. Durability Cycles
As proposed, we are specifying three durability aging cycles to
help ensure durable permeation barriers: slosh, pressure-vacuum
cycling, and ultraviolet (UV) exposure. They represent conditions that
are likely to occur in-use for gas cans, especially for those cans used
for commercial purposes and carried on truck beds or trailers. The
purpose of these deterioration cycles is to help ensure that the
technology chosen by manufacturers is durable in-use, representing best
available control, and the measured emissions are representative of in-
use permeation rates. Fuel slosh, pressure cycling, and ultraviolet
(UV) exposure each impact the durability of certain permeation
barriers, and we believe these cycles are needed to ensure long-term
emissions control. Without these durability cycles, manufacturers could
choose to use materials that meet the standard when they are new but
have degraded performance in-use, leading to higher emissions. We do
not expect these procedures to adversely impact the feasibility of the
standards, because there are permeation barriers available at a
reasonable cost that do not deteriorate significantly under these
conditions (these permeation barriers are examples of best available
controls).
For slosh and pressure cycling, we are finalizing durability tests
that are based on draft recommended SAE practice for evaluating
permeation barriers.\206\ For slosh testing, the container is to be
filled to 40 percent capacity with E10 fuel and rocked for 1 million
cycles. The pressure-vacuum testing contains 10,000 cycles from -0.5 to
2.0 psi. This pressure may be applied through the opening where the
spout attaches, in order to avoid the need to drill a hole in the
container. The third durability test is intended to assess potential
impacts of ultraviolet (UV) sunlight (0.2 [mu]m-0.4 [mu]m) on the
durability of a surface treatment. In this test, the container must be
exposed to a UV light of at least 0.40 Watt-hour/meter \2\ /minute on
the container surface for 15 hours per day for 30 days. Alternatively,
containers may be exposed to direct natural sunlight for an equivalent
period of time. We have also established these same durability
requirements as part of our program to control permeation emissions
from recreational vehicle fuel tanks.\207\ While there are obvious
differences in the use of gas cans compared to the use of recreational
vehicle fuel tanks, we believe the test procedures offer assurance that
permeation controls used by manufacturers will be robust and will
continue to perform as intended when in use.
---------------------------------------------------------------------------
\206\ Draft SAE Information Report J1769, ``Test Protocol for
Evaluation of Long Term Permeation Barrier Durability on Non-
Metallic Fuel Tanks,'' (Docket A-2000-01, document IV-A-24).
\207\ Final Rule, ``Control of Emissions from Nonroad Large
Spark-ignition engines, and Recreational Engines (Marine and Land-
based)'', 67 FR 68287, November 8, 2002.
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Manufacturers may also do an engineering evaluation, based on data
from testing on their permeation barrier, to demonstrate that one or
more of these factors (slosh, UV exposure, and pressure cycle) do not
impact the permeation rates of their fuel containers and therefore that
the durability cycles are not needed. Manufacturers may use data
collected previously on gas cans or other similar containers made with
the same materials and processes to demonstrate that the emissions
performance of the materials does not degrade when exposed to slosh,
UV, and/or pressure cycling. The test data must be collected under
equivalent or more severe conditions as those noted above. EPA must
approve an alternative demonstration method prior to its use for
certification.
b. Preconditioning Fuel Soak
It takes time for fuel to permeate through the walls of containers.
Permeation emissions will increase over time as fuel slowly permeates
through the container wall, until the permeation finally stabilizes
when the saturation point is reached. We want to evaluate emissions
performance once permeation
[[Page 8503]]
emissions have stabilized, to ensure that the emissions standard is met
in-use. Therefore, as proposed, prior to testing the containers, the
cans need to be preconditioned by allowing the cans to sit with fuel in
them until the hydrocarbon permeation rate has stabilized. Under this
step, the container is filled with a 10-percent ethanol blend in
gasoline (E10), sealed, and soaked for 20 weeks at a temperature of 28
± 5 [deg]C. As an alternative, the fuel soak may be
performed, for example, for 10 weeks at 43 ± 5 [deg]C to
shorten the test time, if the certifier can demonstrate that the
hydrocarbon permeation rate has stabilized. During this fuel soak, the
container must be sealed with the spout attached. This is
representative of how the gas cans would be stored in-use. We have
established these soak temperatures and durations based on protocols
EPA has established to measure permeation from fuel tanks made of
HDPE.\208\ These soak times should be sufficient to achieve stabilized
permeation emission rates. However, if a longer time period is
necessary to achieve a stabilized rate for a given container, the
manufacturer must use a longer soak period (and/or higher temperature)
consistent with good engineering judgment.
---------------------------------------------------------------------------
\208\ Final Rule, ``Control of Emissions from Nonroad Large
Spark-ignition engines, and Recreational Engines (Marine and Land-
based)'', 67 FR 68287, November 8, 2002.
---------------------------------------------------------------------------
Durability testing that is performed with fuel in the container may
be considered part of the fuel soak provided that the container
continuously has fuel in it. This approach would shorten the total test
time. For example, the length of the UV and slosh tests may be
considered as part of the fuel soak provided that the container is not
drained between these tests and the beginning of the fuel soak. In such
cases, manufacturers must use the 40 percent fill level for the soak
period. The reduced fill level will not affect the permeation rate of
the container because the vapor space in the container will be
saturated with fuel vapor.
c. Spout Actuation
In its recently revised program for PFCs, California included a
durability demonstration for spouts. We are finalizing as proposed a
durability demonstration consistent with California's procedures.
Automatically closing spouts are a key part of the emissions controls
expected to be used to meet the new standards. If these spouts stick or
deteriorate, in-use emissions could remain very high, at essentially
uncontrolled levels. California requires manufacturers to actuate the
spouts 200 times prior to the soak period and 200 times near the
conclusion of the soak period to simulate spout use. The spouts'
internal components would be required to be exposed to fuel by tipping
the can between each cycle. Spouts that stick open or leak during these
cycles would be considered failed. The total of 400 spout actuations
represents about 1.5 actuations per week on average over the average
container life of 5 years. In the absence of data, we believe this
number of actuations appears to reasonably replicate the number that
can occur in-use for high-end usage and will help ensure quality spout
designs that do not fail in-use. We also believe that finalizing
requirements consistent with California will help manufacturers to
avoid duplicate testing.
One commenter stated that 400 actuations over a short period of
time is not representative of real life and that many containers will
last 15-25 years. In response, we understand that 5 years is an
estimate of the average life and that some containers will be used
longer than 5 years. However, we continue to believe that the approach
we are finalizing is reasonable. This provision is meant to help ensure
that spouts are made of quality materials so that the emissions
performance will not deteriorate readily during normal use. The
provision also helps to ensure that spouts will not break easily or
stick open during normal use, and helps to identify issues during the
certification process prior to sale. In addition, this approach
balances the need to ensure quality designs with the manufacturers'
need to be able to conduct certification testing in a reasonable amount
of time. This type of ``accelerated aging'' of components is a
necessary part of many of EPA's mobile source emissions control programs.
D. What Certification and In-Use Compliance Provisions Is EPA Adopting?
1. Certification
Section 183(e)(4) authorizes EPA to adopt appropriate systems of
regulations to implement the program, including requirements ranging
from registration and self-monitoring of products, to prohibitions,
limitations, economic incentives and restrictions on product use. We
are finalizing as proposed a certification mechanism pursuant to these
authorities. Manufacturers are required to apply for and receive an EPA
certificate of conformity, using the certification process specified in
the regulations, before entering their containers into U.S. commerce.
To have their products certified, manufacturers must first define their
emission families. This is generally based on selecting groups of
products that have similar emissions. For example, co-extruded
containers of various geometries could be grouped together. The
manufacturer must select a worst-case configuration for testing, such
as the thinnest-walled container. Manufacturers may group gasoline,
diesel, and kerosene containers together as long as the containers do
not differ materially in a way that could be anticipated to cause
differences in emissions performance. These determinations must be made
using good engineering judgment and are subject to EPA review. Testing
with those products, as specified above, must show compliance with
emission standards. The manufacturers must then send us an application
for certification. As proposed, we define the manufacturer as the
entity that is in day-to-day control of the manufacturing process
(either directly or through contracts with component suppliers) and
responsible for ensuring that components meet emissions-related
specifications. Importers are not considered a manufacturer under this
program, and thus would not receive certificates. The manufacturers of
the PFCs they import would have to certify the cans. Importers will
only be able to import PFCs that are certified.
After reviewing the information in the application, if all the
required information is provided and it demonstrates compliance with
the standards, then we will issue a certificate of conformity allowing
manufacturers to introduce into commerce the containers from the
certified emission family. We expect EPA review to typically take about
90 days or less, but could be longer if we have questions regarding the
application. The certificate of conformity will be for a production
period of up to 5 years. Manufacturers are allowed to carry over
certification test data if no changes are made to their products that
would affect emissions performance. We may revoke or void a certificate
if we find that data and information on which it is based is false or
inaccurate. We will notify the manufacturer in writing and the
manufacturer may request a hearing. Changes to the certified products
that affect emissions require reapplication for certification.
Manufacturers wanting to make changes without doing testing are
required to present an engineering
[[Page 8504]]
evaluation demonstrating that emissions are not affected by the change.
The manufacturer is responsible for meeting applicable emission
standards. Importers are also responsible for the product meeting the
standards. While we are not including requirements for manufacturers to
conduct production-line testing, we may pursue EPA in-use testing of
certified products to evaluate compliance with emission standards. If
we find that containers do not meet emissions standards in use, we
would consider the new information during future product certification.
Also, we may require certification prior to the end of the 5-year
production period otherwise allowed between certifications. The details
of the certification process are provided in the regulatory text. We
did not receive any comments on the certification procedures described
above.
EPA is authorized under the Independent Offices Appropriation Act
of 1952 to establish fees for Government services and things of value
that it provides. This provision encourages Federal regulatory agencies
to recover, to the fullest extent possible, costs provided to
identifiable recipients. The agency currently collects fees for
compliance programs administered by EPA including those for
certification of motor vehicles and motor vehicle engines. At this
time, we are not finalizing a fee program for PFC certification.
However, we may establish a certification fee for PFCs in a future
rulemaking.
2. Emissions Warranty and In-Use Compliance
We are finalizing as proposed an emissions warranty period of one
year to be provided by the manufacturer of the PFC to the consumer. The
warranty covers emissions-related materials defects and breakage under
normal use. For example, the warranty covers failures related to the
proper operation of the auto-closing spout or defects with the
permeation barriers. We are also requiring that manufacturers submit a
warranty and defect report documenting successful warranty claims and
the reason for the claim to EPA annually so that EPA may monitor the
program. Unsuccessful claims will not need to be submitted. We believe
that this warranty will encourage designs that work well for consumers
and are durable. Although it does not fully cover the average life of
the product, it is not typical for very long consumer warranties to be
offered with such products and therefore we believe a one-year warranty
is reasonable. Also, the warranty period is more similar to the
expected life of gas cans when used in commercial operations, which
would need to be considered by the manufacturers in their designs. We
did not receive any comments on these warranty provisions.
EPA views this aspect of the final rule as another part of the
``system of regulation'' it is finalizing to control VOC emissions from
PFCs. A warranty will promote the objective of the rule by providing
consumers with an opportunity to replace containers that have failed in
use. The warranty provides an obvious remedy to consumers if issues
arise. The provision also helps to ensure that manufacturers will
``stand behind'' their product if they fail in use, thus improving
product design and performance. Similarly, the defect reporting
requirement will promote product integrity by allowing EPA to readily
monitor in-use performance by tracking successful warranty claims.
Gas cans have a typical life of about 5 years on average before
they are scrapped. We are including durability provisions as part of
certification testing to help ensure containers perform well in use.
Under this final rule, we could test containers within their five-year
useful life period to monitor in-use performance and take steps to
correct in-use failures, including denying certification, for container
designs that are consistently failing to meet emissions standards.
(This provision thus would work in tandem with the warranty claim
reporting provision contained in the preceding paragraph.)
3. Labeling
Since the requirements will be effective based on the date of
manufacture of the container, we are requiring as proposed that the
date of manufacture must be indelibly marked on the can. This is
consistent with current industry practices. This is needed so that we
and others can recognize whether a unit is regulated or not. In
addition, we are requiring a label providing the manufacturer name and
contact information, a statement that the can is EPA certified,
citation of EPA regulations, and a statement that it is warranted for
one year from the date of purchase. The manufacturer name and contact
information is necessary to verify certification. Indicating that a
one-year warranty applies will ensure that consumers have knowledge of
the warranty and a way to contact the manufacturer. Enforcement of the
warranty is critical to the defect reporting system. In finalizing this
labeling requirement, we further believe, pursuant to CAA section
183(e)(8), that these labeling requirements will be useful in meeting
the NAAQS for ozone. They provide necessary means of implementing the
various measures described above which help ensure that VOC emission
reductions from the proposed standard will in fact occur in use. We did
not receive any comments on these labeling requirements.
E. How Would State Programs Be Affected By EPA Standards?
Several states have adopted emissions control programs for PFCs.
California implemented an emissions control program for PFCs in 2001.
Fifteen other states, mostly in the northeast, have adopted or are
considering adopting the California program.\209\ In 2005, California
adopted a revised program, which will go into effect on July 1, 2007.
The revised California program is very similar to the program we are
finalizing. We believe that although a few aspects of the program we
are finalizing are different, manufacturers will be able to meet both
EPA and CARB requirements with the same container designs and therefore
sell a single product in all 50 states. In most cases, we believe
manufacturers will take this approach. By closely aligning with
California where possible, we will allow manufacturers to minimize
research and development (R&D) and emissions testing, while potentially
achieving better economies of scale. It may also reduce administrative
burdens and market logistics from having to track the sale of multiple
can designs. We consider these to be important factors under CAA
section 183(e) which requires us to consider economic feasibility of
controls.
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\209\ Delaware, Maine, Maryland, Pennsylvania, New York,
Connecticut, Massachusetts, New Jersey, Rhode Island, Vermont,
Virginia, Washington DC, Texas, Ohio, and New Hampshire.
---------------------------------------------------------------------------
States that have adopted the original California program will
likely choose to either adopt the new California program or eliminate
their state program in favor of the federal program. Because the
programs are similar, we expect that most states will eventually choose
to rely on implementation of the EPA program rather than continue their
own program. Including diesel and kerosene containers in our final
program further aligns the two programs and several states commented in
support of this approach. We expect very little difference in the
emissions reductions provided by the EPA and California programs in the
long term.
[[Page 8505]]
F. Provisions for Small PFC Manufacturers
As discussed in previous sections, prior to issuing our proposal
for this rulemaking, we analyzed the potential impacts of these
regulations on small entities. As a part of this analysis, we convened
a Small Business Advocacy Review Panel (SBAR Panel, or ``the Panel'').
During the Panel process, we gathered information and recommendations
from Small Entity Representatives (SERs) on how to reduce the impact of
the rule on small entities, and those comments are detailed in the
Final Panel Report which is located in the public record for this
rulemaking (Docket EPA-HQ-OAR-2005-0036). Based upon these comments, we
proposed to include flexibility and hardship provisions for container
manufacturers. Since nearly all manufacturers are small entities and
they account for about 60 percent of sales, the Panel recommended that
we extend the flexibility options and hardship provisions to all
manufacturers. Our proposal was consistent with that recommendation. We
did not receive any comments on our proposed flexibilities and are
finalizing them as proposed. The flexibility provisions are
incorporated into the program requirements described earlier in
sections VII.B through VII.D. The hardship provisions are described
below. For further discussion of the Panel process, see section X.C of
this rule and/or the Final Panel Report.
The Panel recommended and we are finalizing two types of hardship
provisions for container manufacturers. These entities could, on a
case-by-case basis, face hardship, and we are finalizing these
provisions to provide what could prove to be needed safety valves for
these entities. Thus, the hardship provisions are as follows:
1. First Type of Hardship Provision
Container manufacturers may petition EPA for limited additional
lead-time to comply with the standards. A manufacturer would have to
demonstrate that it has taken all possible business, technical, and
economic steps to comply but the burden of compliance costs prevents it
from meeting the requirements of this subpart by the required
compliance date and not having an extension would jeopardize the
company's solvency. Hardship relief may include requirements for
interim emission reductions.
2. Second Type of Hardship Provision
Container manufacturers are permitted to apply for hardship relief
if circumstances outside their control cause the failure to comply
(i.e., an ``Act of God,'' a fire at the manufacturing plant, or the
unforeseen shut down of a supplier with no alternative available), and
if failure to sell the subject containers would jeopardize the
company's solvency. The terms and timeframe of the relief will depend
on the specific circumstances of the company and the situation
involved.
For both types of hardship provisions, the length of the hardship
relief will be established, during the initial review, for not more
than one year and will be reviewed annually thereafter as needed. As
part of its application, a company is required to provide a compliance
plan detailing when and how it will achieve compliance with the standards.
VIII. What Are the Estimated Impacts of the Rule?
A. Refinery Costs of Gasoline Benzene Reduction
The benzene control program we are finalizing today is expected to
result in many refiners investing in benzene control hardware and
changing the operations in their refineries to reduce their gasoline
benzene levels. The finalized benzene control program requires refiners
and importers to reduce their gasoline benzene levels on average down
to 0.62 vol% benzene. The averaging, banking and trading (ABT)
provisions being finalized along with the 0.62 vol% average benzene
control standard allows refineries that reduce their gasoline benzene
levels below 0.62 vol% to earn credits and transfer those credits to
other refineries which would find it more expensive to reduce their
benzene levels down to the average standard. The ABT program will allow
refiners to optimize their investments, which we believe will result in
achieving the average benzene control standard nationwide at much lower
costs. The final benzene control program also puts into place a 1.3
vol% benzene maximum average standard which requires each refinery to
reduce its gasoline benzene levels to or below this standard and will
increase the benzene control costs only slightly compared to a benzene
control program which does not contain a maximum average standard. We
estimate that the national average refinery costs incurred to comply
with the fully phased-in benzene control program will be 0.27 cents per
gallon, averaged over all gasoline. This estimate includes the capital
costs, which are amortized over the volume of gasoline produced.
In this section we summarize the methodology used to estimate the
costs of benzene control (including changes we have made since the
proposal) and our estimated costs for the program. In addition we
evaluate the cost estimate provided by the American Petroleum
Institute. A detailed discussion of all of these analyses is found in
Chapter 9 of the RIA.
1. Methodology
a. Overview of the Benzene Program Cost Methodology
The basic methodology we used to estimate the cost of benzene
control for the final rule is the same as that used for the proposed
rule. Using a refinery-by-refinery cost model that we developed for
this rulemaking, we projected which refineries implement what benzene
control technology, and the cost of each refinery's benzene control
step, to estimate compliance with the final benzene control program. We
aggregated the individual refinery costs to develop a national average
cost estimate for the final benzene control program. Based on the
flexibilities offered by the ABT program, refiners are expected to come
very close to achieving the 0.62 vol% average benzene standard on
average with little overcompliance. For this reason, we modeled
refiners achieving the average standard without any overcompliance. To
the extent that any overcompliance does occur the costs and benefits of
the benzene program will increase.
b. Changes to the Cost Estimation Methodology Used in the Proposed Rule
In deriving the cost estimate for the final rule, we identified and
made a number of changes to the refinery modeling methodology used for
the proposed rule. One of the primary changes was to base the future
year fuel prices on the Annual Energy Outlook (AEO) 2006 instead of AEO
2005, which increased the crude oil price used in the analysis from $27
per barrel to $47 per barrel. Other changes included: (1) Updating the
refinery modeling base year to 2004 (used for calibrating each
refinery's gasoline benzene levels); (2) modeling the baseline benzene
levels and reductions on an annual basis instead of on a summer-only
basis; (3) increasing the tax-hurdle rate of return to 15 percent from
the 10 percent hurdle used in the proposed rule, and (4) including the
treatment of the benzene in natural gasoline, which was assumed to be
left untreated in the proposed rule analysis.
[[Page 8506]]
In addition, we also made some adjustments that were based on
comments we received on the cost analysis that we conducted for the
proposal, as well as the peer review process that we undertook for the
proposal's refinery cost model. One of the peer reviewers for the
refinery-by-refinery cost model, and API in its comments on the
proposed rule, provided capital cost estimates for the benzene control
technologies.\210\ We reviewed these capital cost estimates and made
some adjustments to somewhat increase the capital cost figures used in
the final rule analysis. These changes were partially responsible for
the higher costs reported here compared to those reported in the
proposed rule. More complete descriptions of these and other changes
made to the refinery cost model are contained in Chapter 9 the RIA.
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\210\ An important reason for the discrepancy between our
capital cost estimate and that by API (which was about three times
higher) was that we only estimated the capital costs related to the
benzene control technologies, not those related to octane recovery
and increased hydrogen production needed for saturation or to
replace the octane lost due to reduced benzene production by the
reformer. For the final rule, we estimated these additional capital
costs and included them in our capital cost estimates.
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c. Linear Programming Cost Model
We considered performing our cost assessments using a linear
programming (LP) cost model. LP cost models are based on a set of
complex mathematical representations of refineries which, for national
analyses, are usually conducted on a regional basis. This type of
refining cost model has been used by the government and the refining
industry for many years for estimating the cost and other implications
of changes to fuel quality.
The design of LP models lends itself to modeling situations where
every refinery in a region is expected to use the same control strategy
and/or has the same process capabilities. As we began to develop a
gasoline benzene control program with an ABT program, it became clear
that LP modeling was not well suited for evaluating such a program.
Because refiners will be choosing a variety of technologies for
controlling benzene, and because the program will be national and will
include an ABT program, we initiated development of a more appropriate
cost model, as described below. However, the LP model remained
important for providing many of the inputs into the cost model
developed for this rulemaking.
d. Refinery-by-Refinery Cost Model
In contrast to LP models, refinery-by-refinery cost models are
useful when individual refineries are expected to respond to program
requirements in different ways and/or have significantly different
process capabilities. Thus, in the case of modeling gasoline benzene
control programs, we needed a model that could accurately simulate the
variety of decisions refiners will make at different refineries,
especially in the context of a nationwide ABT program. For this and
other related reasons, we developed a refinery-by-refinery cost model
specifically to evaluate the benzene control program.
Our refinery-by-refinery benzene cost model incorporates the
capacities of all the major units in each refinery in the country, as
reported by the Energy Information Administration and in the Oil and
Gas Journal. Regarding operational information, we know less about how
specific refineries use the various units to produce gasoline and about
such factors as octane and hydrogen costs for individual refineries. We
used the LP model to estimate these factors on a regional basis, and we
applied the average regional result to each refinery in that region
(PADD). We calibrated the model for each individual refinery based on
2004 gasoline volumes and benzene levels (from the RFG data base),
which was the most recent year for which data was available. After
calibration, each refinery's gasoline volume and benzene level closely
matched their actual gasoline volumes and benzene levels. We also
compared cost estimates of similar benzene control cases from both the
refinery-by-refinery model and the LP model, and the results were in
close agreement.\211\
---------------------------------------------------------------------------
\211\ Despite our commitment to accurately model the baseline
operations of each refinery, we recognize that without detailed
refinery-specific operations information at our disposal, that our
modeling may not be accurate in some specific cases. Particular
refineries may choose a different benzene control path than that
estimated by our analysis for a number of reasons, including
differences in the baseline and our lack of knowledge for investment
and ABT program use preferences for each refiner. We believe,
though, that overall our refinery cost model captures the strategies
and costs for complying with the benzene control program.
---------------------------------------------------------------------------
Refinery-by-refinery cost models have been used in the past by both
EPA and the oil industry for such programs as the highway and nonroad
diesel fuel sulfur standards, and they are a proven means for
estimating the cost of compliance for fuel control programs. For this
refinery-by-refinery benzene cost model, we conducted a peer review
process, and have received some comments on the design of our model. We
summarize some of these comments here, and they are summarized and
addressed in detail in the RIA. (See Chapter 9 of the RIA for our
responses to these peer-review comments.) The oil industry has also
conducted similar analyses using a refinery-by-refinery modeling
technique, including the oil industry's cost analysis carried out for
this rulemaking.
Based on our understanding of the primary benzene control
technologies (see section VI.A.1.c.i. above), the cost model assumes
that four technologies will be used, as appropriate, for reducing
benzene levels. All of these technologies focus on addressing benzene
in the reformate stream. They are (1) routing the benzene precursors
around the reformer (also called light naphtha splitting and reformer
feed fractionation); (2) routing benzene precursors to an existing
isomerization unit, if available; (3) benzene extraction (extractive
distillation); and (4) benzene saturation. For the proposed rulemaking
we assumed that only the usual feed or the product stream of the
reformer will be processed by these benzene control technologies.
However, since the proposal, we learned that another refinery stream--
natural gasoline--contains some benzene and will likely be treated by
the saturation and extraction processes in refineries if they have or
install these units. For the proposal, we assumed that natural gasoline
would be blended directly into gasoline and not be treated by refiners
if faced with a benzene control standard. However, most refiners have
been combining natural gasoline with their crude oil to enable treating
the sulfur in natural gasoline to help comply with the Tier 2 gasoline
sulfur standard. Because the natural gasoline will be refined along
with crude oil, the benzene in natural gasoline can and will be treated
along with the benzene in crude oil.
The nationwide ABT program is intended to optimize benzene
reduction by allowing each refinery to individually choose the most
cost-effective means of complying with the program. To model this
phenomenon, we first established an estimated cost for the array of
technologies that could be employed by each refinery to reduce its
gasoline benzene levels. We then deployed these technologies to
refineries with baseline benzene levels above the 1.3 vol% benzene
maximum average standard to bring them into compliance with this
standard. Next we ranked the refineries in order from lowest to highest
benzene control cost per gallon of gasoline and estimated the impact of
their projected benzene
[[Page 8507]]
control strategies on refinery benzene levels. The model then follows
this ranking, starting with the lowest-cost refineries, and adds
refineries and their associated control technologies one-by-one until
the projected national average benzene level reaches 0.62 vol% benzene.
This modeling strategy projects the benzene control technology that
will be used by each refinery, as well as identifies those refineries
that are expected to generate credits and those that are expected to
use credits in lieu of investing in benzene control. The sum of the
costs of the refineries expected to invest in benzene control provides
the projected overall cost of the program.
Finally, we projected how the ABT program will affect the program
cost and benzene levels starting in 2007, when early credits can be
generated. We assumed that refiners will use operational changes
(benzene precursor rerouting, with isomerization if available) to the
maximum extent possible in mid-2007, when they are able to start to
generate credits. We also assumed that refiners will choose to
accumulate additional early credits by making their initial lowest-cost
capital investments for reducing their gasoline benzene levels, and
that these changes will take effect in 2010. We modeled compliance by
nonsmall and small refiners with the maximum average standard taking
effect in mid-2012 and the beginning of 2015, respectively, as well as
the final benzene control step to meet the 0.62 vol% standard--the
phase-in of which depends on the aggregate amount of credits generated.\212\
---------------------------------------------------------------------------
\212\ The ABT analysis assumed that small refiners would comply
with the 1.3 vol% maximum average standard in January 2015 at the
same time as the 0.62 vol% annual average standard. We are
finalizing a later maximum average standard implementation date
(July 2016), which will have very little effect on the overall
program and therefore has not been incorporated into this analysis.
---------------------------------------------------------------------------
e. Price of Chemical Grade Benzene
The price of chemical grade benzene is critical to the benzene
control program because it defines the opportunity cost for benzene
removed using benzene extraction and sold into the chemicals market.
According to 2004 World Benzene Analysis authored by Chemical Market
Associates Incorporated (CMAI), during the consecutive five-year period
ending with 2004, the price of benzene averaged 24 dollars per barrel
higher than regular grade gasoline. During the three consecutive year
period ending with 2004, the price of benzene averaged 28 dollars per
barrel higher than regular grade gasoline. However, during the first
part of 2004, the price of benzene relative to gasoline rose steeply,
primarily because of high energy prices adding to the cost of
extracting benzene. The 2004 benzene price averaged 78 dollars per
barrel higher than regular grade gasoline. Since early 2006, CMAI has
been projecting that the future price of benzene relative to gasoline
will return to more historic levels, in the range of 30 dollars per
barrel higher than regular grade gasoline (in 2005, CMAI was projecting
that the benzene price would be 20 dollars per barrel higher than
gasoline). We have based our modeling for the final rule on the 30
dollar per barrel value.
2. Summary of Costs
a. Nationwide Costs of the Final Benzene Control Program
We have used the refinery-by-refinery cost model to estimate the
costs of the benzene control program being finalized today. In general,
the cost model indicates that among the four primary reformate-based
technologies, benzene precursor rerouting will be the most cost-
effective. The next most cost-effective technologies are isomerization
of the rerouted light straight run material, revamped extraction units
and new installations of large extraction units. The model indicates
that benzene saturation and small installations of new extraction units
will be the least cost-effective.
Based on the results of our analysis using the refinery-by-refinery
model, we estimate that when the benzene control program is fully
phased in, 78 refineries of the total 104 gasoline-producing refineries
in the U.S. (outside of California) will have to put in new capital
equipment or change their refining operations to reduce the benzene
levels in their gasoline. Of these refineries, we estimate that 17 will
use benzene precursor removal, 28 refineries will use benzene precursor
removal coupled with isomerization, 16 will use extraction, and 17 will
use benzene saturation. We project that 52 refineries will continue to
produce gasoline with benzene levels greater than the average standard
and will need to purchase credits to comply. Including the refineries
with benzene levels currently below 0.62, we project that there will be
a total of 50 refineries that will produce gasoline with benzene levels
at 0.62 or lower and will generate credits for sale to other
refineries. Finally, the model projects that 26 refineries will take no
steps to reduce their gasoline benzene levels, which includes those
which remain above the average benzene standard as well as those
already below the average standard.
Based on the results of our cost analysis, we estimate that the
final benzene control program will cost 0.27 cents per gallon when it
is fully phased in, assuming that capital investments are amortized at
a 7 percent return on investment before taxes and expressed in 2003
dollars. Our cost analysis projects that the ABT program will result in
a phase-in of the benzene control standard from mid-2007 to early in
2015. Starting in mid-2007 we believe that refiners will take the
opportunity to achieve modest benzene reductions to generate early
credits using simple operational changes. We project that these actions
taken in mid-2007 will result in a reduction of the average U.S.
gasoline benzene level from 0.99 to 0.81 vol% at an average cost of
0.04 cents per gallon.
To take full advantage of the flexibility provided to refiners by
the ABT program to delay more expensive capital investments, refiners
are expected to make additional early benzene reductions to generate
more early credits, requiring modest investments in capital. Because of
the time it takes to assess, design and install the capital equipment,
we project that these additional early benzene reductions will not
occur until the beginning of 2010, although in reality these
investments and associated benzene reductions would likely occur before
and after the beginning of 2010. These benzene reductions are expected
to further reduce the average benzene level of U.S. gasoline to 0.74
vol% and cost 0.05 cents per gallon averaged over all U.S. gasoline.
Refiners are expected to make $324 million of capital investments to
achieve this benzene reduction. In 2011 when the 0.62 vol% benzene
control standard takes effect, we do not anticipate any further
reduction in benzene because we project that the refining industry will
be able to comply using early credits.
In mid-2012, when refineries with high benzene levels need to
comply with the 1.3 vol% maximum average standard, we anticipate that
U.S. gasoline benzene levels will decline further, to 0.73 vol%
benzene, and cost an additional 0.04 cents per gallon averaged over all
U.S. gasoline. Refiners are expected to make another $153 million in
capital investments. Although the early credit use period terminates at
the end of 2013, refiners will again have flexibility in scheduling
their most expensive capital
[[Page 8508]]
investments by using standard credits (which will have been accruing
since the start of 2011). Because we expect that refiners will first
use their early credits, the standard credits will be banked and will
start to be used in 2014 to show compliance with the 0.62 vol% benzene
standard. Our analysis suggests that the U.S. refining industry will be
able to delay their highest capital investments until May 2015, when
the standard credits accumulated since the beginning of 2011 run out.
Small refiners must meet the 1.3 vol% maximum average standard which
was assumed to occur at the beginning of 2015 so they also will be
reducing their gasoline benzene levels to that standard or below.\213\
Taken together, these reductions in 2015 will bring the U.S. gasoline
pool down to the 0.62 vol% benzene standard at an average cost of 0.14
cents per gallon averaged over all U.S. gasoline, based on the addition
of $634 million in capital investments.
---------------------------------------------------------------------------
\213\ The ABT analysis assumed that small refiners would comply
with the 1.3 vol% maximum average standard in January 2015 at the
same time as the 0.62 vol% annual average standard. We are
finalizing a later maximum average standard implementation date
(July 2016), which will have very little effect on the overall
program and therefore has not been incorporated into this analysis.
---------------------------------------------------------------------------
To comply with the fully phased-in final benzene control program,
refiners are expected to have made a total of $1110 million in capital
investments. This will amount to an average of $14 million in capital
investment in each refinery that adds such equipment.
We also estimated annual aggregate costs, including the amortized
capital costs, associated with the new fuel standard. As shown in Table
VIII.A-1, these costs are projected to begin at $28 million in 2007 and
increase to $363 million in 2015 when the benzene program is fully
phased in. These aggregated costs continue to increase over time as
fuel demand increases.
Table VIII.A-1.--Per-Gallon and Annual Aggregate Fuel Costs for the
Final Benzene Control Program
(7% ROI before taxes and 2003 dollars)
------------------------------------------------------------------------
Per-gallon Aggregate
Year cost (c/ cost
gal) ($million)
------------------------------------------------------------------------
2007.......................................... 0.02 28
2008.......................................... 0.04 49
2009.......................................... 0.04 50
2010.......................................... 0.09 101
2011.......................................... 0.09 104
2012.......................................... 0.11 133
2013.......................................... 0.13 164
2014.......................................... 0.13 166
2015.......................................... 0.27 363
2020.......................................... 0.27 388
2025.......................................... 0.27 412
2030.......................................... 0.27 437
2035.......................................... 0.27 464
------------------------------------------------------------------------
Several observations can be made from these results of our
nationwide cost analysis. First, significantly reducing gasoline
benzene levels to low levels, coupled with the flexibility of an ABT
program, will incur fairly modest aggregate program costs. This is
primarily because we expect that refiners will optimize their benzene
control strategies, resulting in large benzene reductions at a
relatively low overall program cost. With higher benzene prices
relative to those of gasoline projected to continue (even if they drop
from the recent very high levels), extraction is expected to be a very
low-cost technology--the primary reason why the cost of the overall
program is very low. Also, precursor rerouting, either with or without
isomerization in an existing unit, is a low-cost technology requiring
little or no capital to realize. The model concludes that even the
higher-cost benzene saturation technology will be fairly cost-effective
overall because larger refineries that install this technology will
take advantage of their economies of scale.
b. Regional Costs
The benzene reductions estimated by the cost model and associated
costs vary significantly by region. Table VIII.A-2 summarizes the
estimated per-gallon costs for complying with the benzene control
standard by PADD region.
Table VIII.A-2.--Projected Benzene Control Costs by PADD for the Final Benzene Control Program
(2003 dollars, 7% ROI before taxes)
----------------------------------------------------------------------------------------------------------------
PADD
---------------------------------------------
5 (w/o U.S.
1 2 3 4 CA)
----------------------------------------------------------------------------------------------------------------
Cost (c/gal).............................................. 0.14 0.35 0.15 0.55 1.21 0.268
----------------------------------------------------------------------------------------------------------------
Table VIII.A-2 shows that the PADD-average costs are highest in
PADD 5 followed next by PADD 4. In PADDs 1, 2 and 3, where reformulated
gasoline programs have already forced gasoline benzene levels lower,
the benzene control costs are lower. Extraction is the technology most
used in PADDs 1 and 3, resulting in lower benzene control cost in these
regions. Individual refineries show a wider range of control costs than
the PADD-average costs. There are 20 refineries for which we estimate
benzene control costs lower than 0.20 cents per gallon. Also, there are
11 refineries, all of which are very small refineries, with costs in
the range of 3 to 7 cents per gallon range.
c. Refining Industry Cost Study
The American Petroleum Institute (API) conducted its own refinery
modeling study to evaluate the cost of benzene control. The API study
analyzed the cost of three different benzene control programs. Two of
the benzene control programs analyzed by API were very different than
our final benzene control program and we will not discuss them here
(see Chapter 9 of the RIA). The third program analyzed by API was
nearly identical to the final benzene control standard, and we have
carefully compared API's cost analysis to ours.
API analyzed a benzene control program with a nationwide 0.60 vol%
benzene standard and with an ABT program and with no upper benzene
limit. API also assumed that credits will not be traded freely, but
instead that refining companies would hold onto 10 percent of their
credits in case they have a future problem with their benzene control
unit. Including the compliance margin and the 10 percent credit margin,
the API study estimated that under its modeled benzene control program
and associated assumptions that U.S. gasoline would average 0.56 vol%
benzene. The API study estimates the cost of complying with its modeled
benzene control program to be 1.00 cent
[[Page 8509]]
per gallon.\214\ This estimated benzene control cost is substantially
higher than our estimated 0.27 cents per gallon cost for our nearly
identical program. After comparing their methodology to ours we
identified three primary differences which explain the large difference
in costs.
---------------------------------------------------------------------------
\214\ This cost estimate includes an adjustment we made to
convert the API capital cost amortization from the after-tax 10
percent rate of return that was the basis for the estimated costs in
their report to a before-tax 7 percent rate of return, which is how
our rules are estimated.
---------------------------------------------------------------------------
The first difference is that API modeled a somewhat lower benzene
control standard and assumed a credit generation margin which resulted
in refiners achieving a much lower benzene level than the 0.62 vol%
benzene control standard. A primary reason why the refining industry
study modeled overcompliance with the benzene standard is due to an
assumption that refiners will want to hold onto a substantial quantity
of credits, yet the API cost study did not provide a justification for
the accumulation of credits. EPA does not believe that refiners will
significantly overcomply with the average benzene standard. This is
because the 0.62 vol% benzene standard is an averaging standard which
is met across the entire industry, not a cap standard, and can be met
by the accumulation of gasoline batches with benzene levels higher or
lower than the standard. Thus, if a refinery produced gasoline with
lower or higher gasoline benzene levels over the first part of the
year, the operations could be adjusted to balance out the gasoline
benzene levels for the rest of the year. Also, our program includes
several provisions which give refiners significant flexibility for
compliance. For example, refiners could overcomply slightly with the
standard early on in the program's implementation and hold onto the
credits for up to five years before they expire. If a refinery's
benzene control unit goes down, the refiner would be able to use those
accumulated credits, the refiner could purchase credits from other
refineries, or the refiner could create a benzene reduction deficit at
that refinery and make it up the following year. With this degree of
flexibility, any significant overcompliance with the 0.62 vol% average
benzene standard is unnecessary.
The second reason why the API costs are much higher than ours is
because API used a more restrictive assumption with respect to benzene
extraction--a more cost-effective benzene control technology than
benzene saturation, as discussed above. API assumed that no new
grassroots benzene extraction capacity will be installed in the future,
but that existing extraction units could be expanded. We agree that
existing units will likely be expanded. However, we also believe that
several refineries will install new grassroots extraction units. Our
premise is supported by CMAI projections of a robust benzene market in
the future with benzene priced higher than its historical margin above
gasoline. Higher benzene price margins will provide an incentive to
refiners to add grassroots benzene extraction units, even in areas
where benzene markets are smaller. For example, one refiner has
indicated to us that if the proposed gasoline benzene standard was to
be finalized, it would install a grassroots benzene extraction unit at
one of its refineries in the Midwest, where the benzene market is small
with less room for increased supply (although this benzene could be
shipped down to the Gulf Coast). This is a strong indicator that new
grassroots benzene extraction units will also be installed on the Gulf
and East Coasts, where benzene markets are much larger with much more
room to absorb increased supply.
The third reason why the API benzene control costs are much higher
than ours is their very high octane control costs. For both studies,
the octane loss that occurs due to the modeled application of the
various benzene control technologies is accounted for by assigning a
dollar per octane-barrel cost to the octane loss. However, API's costs
for restoring octane are higher than the future octane recovery costs
that we are projecting. The octane costs used by API are higher because
API used the rack price differential between premium and regular grade
gasolines as summarized by the Energy Information Administration.
However, the rack price differential between premium and regular grade
gasolines reflects a significant amount of profit. For example, the
cost difference to produce premium gasoline is usually only a few cents
per gallon more than for producing regular grade gasoline, yet refiners
and marketers usually charge 20 to 30 cents more per gallon for premium
gasoline at retail. Some of this inflated price appears at the rack
price differential between regular and premium grades of gasoline. In
addition, future octane control costs, when the benzene control
standard takes effect, are expected to be much lower due to the very
large volume of ethanol that is expected to enter the gasoline market
by then.
Overall, we have carefully evaluated the differences between our
cost analysis and that provided by API. Except for the differences
described above, the assumptions used and the conclusions reached were
very similar. We believe our revised analysis provides a more accurate
assessment of the costs of the benzene control program.
B. What Are the Vehicle Cost Impacts?
In assessing the economic impact of setting cold temperature
emission standards, we have made a best estimate of the necessary
vehicle modifications and their associated costs. In making our
estimates we have relied on our own technology assessment, which
includes information supplied by individual manufacturers and our own
in-house testing. Estimated costs typically include variable costs (for
hardware and assembly time) and fixed costs (for research and
development, retooling, and certification). All costs are presented in
2003 dollars. Full details of our cost analysis can be found in Chapter
8 of the RIA.
As described in section V, we are not expecting hardware changes to
Tier 2 vehicles in response to new cold temperature standards. Tier 2
vehicles are already being equipped with very sophisticated emissions
control systems. We expect manufacturers to use these systems to
minimize emissions at cold temperatures. We were able to demonstrate
significant emissions reductions from a Tier 2 vehicle through
recalibration alone. In addition, the standard we are finalizing is
based on averaging which allows some vehicles to be above the numeric
standard as long as those excess emissions are offset by vehicles below
the standard. Averaging will help manufacturers in cases where they are
not able to achieve the numeric standard for a particular vehicle
group, thus helping manufacturers avoid costly hardware changes. The
phase-in of standards and emissions credits provisions also help
manufacturers avoid situations where expensive vehicle modifications
will be needed to meet the new cold temperature NMHC standard.
Therefore, we are not projecting hardware costs or additional assembly
costs associated with meeting new cold temperature NMHC emissions standards.
Manufacturers will incur research and development (R&D) costs
associated with a new cold temperature standard, and some likely will
need to upgrade testing facilities to handle an increased number of
cold tests during vehicle development. We have estimated the fixed
costs associated with R&D and test facilities. We project that
manufacturers will recover R&D costs over a five-year
[[Page 8510]]
period and their facilities costs over a ten-year period. Long-term
impacts on engine costs are expected to decrease as manufacturers fully
amortize their fixed costs. Because manufacturers recoup fixed costs
over a large volume of vehicles, average per vehicle costs due to the
new cold temperature NMHC standards are expected to be low. We project
that the average incremental costs associated with the new cold
temperature standards will be less than $1 per vehicle.
We did not receive comments on the methodology we used to derive
average cost estimates. However, we did receive comments from one
manufacturer with a limited product line who believes new hardware will
be needed on its vehicles to meet the new cold temperature standards.
Other manufacturers did not comment that hardware changes would be
needed, and they generally supported our lead-time, phase-in, and other
transitional provisions as providing the flexibility needed to meet the
standards. We continue to believe that manufacturers will be able to
meet the standards through vehicle development without additional
hardware. However, we conducted a sensitivity analysis in response to
this comment, assuming the commenter would use new hardware to meet the
cold temperature standard. If one percent of new vehicles required
additional hardware costing $100-$200 per vehicle, the average cost
would increase from less than $1 to the range of $1.60-$2.60 per
vehicle. The commenter did not provide cost information in their
comments and we believe that the costs used in our sensitivity analysis
are conservatively high, given the lead time provided for vehicle
development and market pressures to keep costs in line with those of
competitors. In any event, we believe the costs associated with the
program are reasonable. Additional discussion of the comments received
on the vehicle cold temperature standard is provided in Chapter 3 of
the Summary and Analysis of Comments for this rule.
We are not anticipating additional costs for the new evaporative
emissions standard. As discussed in section V, we expect that
manufacturers will continue to produce 50-state evaporative systems
that meet LEV II standards. Therefore, harmonizing with California's
LEV-II evaporative emission standards will streamline certification and
be an ``anti-backsliding'' measure. It also codifies the approach
manufacturers have already indicated they are taking for 50-state
evaporative systems.
We also estimated annual aggregate costs associated with the new
cold temperature emissions standards. These costs are projected to
increase with the phase-in of standards and peak in 2014 at about $13.4
million per year, then decrease as the fixed costs are fully amortized.
The projected aggregate costs are summarized below, with annual
estimates provided in Chapter 8 of the RIA.
Table VIII.B-1.--Annual Aggregate Costs
----------------------------------------------------------------------------------------------------------------
2010 2012 2014 2016 2018 2020
----------------------------------------------------------------------------------------------------------------
$11,119,000..................... $12,535,000 $13,406,000 $12,207,000 $10,682,000 $0
----------------------------------------------------------------------------------------------------------------
C. What Are the PFC Cost Impacts?
For PFCs, we have made a best estimate of the necessary
technologies and their associated costs. Estimated costs include
variable costs (for hardware and assembly time) and fixed costs (for
research and development, retooling, and certification). The analysis
also considers fuels savings associated with low emission PFCs. Cost
estimates based on the projected technologies represent an expected
change in the cost of PFCs as they begin to comply with new emission
standards. All costs are presented in 2003 dollars. We did not receive
comments on estimated costs for PFCs controls. Full details of our cost
analysis, including fuel savings, can be found in Chapter 10 of the RIA.
Table VIII.C-1 summarizes the projected near-term and long-term per
unit average costs to meet the new emission standards. Long-term
impacts on PFCs are expected to decrease as manufacturers fully
amortize their fixed costs. We project that manufacturers will
generally recover their fixed costs over a five-year period, so these
costs disappear from the analysis after the fifth year of production.
These estimates are based on the manufacturing cost rather than
predicted price increases.\215\ The table also shows our projections of
average fuel savings over the life of the PFC when used with gasoline.
Fuel savings can be estimated based on the VOC emissions reductions due
to controls.
---------------------------------------------------------------------------
\215\ These costs numbers may not necessarily reflect actual
price increases as manufacturer production costs, perceived product
enhancements, and other market impacts will affect actual prices to
consumers.
Table VIII.C-1.--Estimated Average Per Unit PFC Costs and Lifetime Fuel
Savings
------------------------------------------------------------------------
Cost
------------------------------------------------------------------------
Near-Term Costs.............................................. $2.69
Long-Term Costs.............................................. 1.52
Fuel Savings (NPV)........................................... 4.24
------------------------------------------------------------------------
With current and projected estimates of PFC sales, we translate
these costs into projected direct costs to the nation for the new
emission standards in any year. A summary of the annual aggregate costs
to manufacturers is presented in Table VIII.C-2. The annual cost
savings due to fuel savings start slowly, then increase as greater
numbers of compliant PFCs enter the market. Table VIII.C-2 also
presents a summary of the estimated annual fuel savings. Aggregate
costs are projected to peak in 2013 at about $61 million and then drop
to about $34 million once fixed costs are recovered. The change in
numbers beyond 2015 occurs due to projected growth in sales and population.
Table VIII.C-2.--Total Annualized Costs and Fuel Savings
----------------------------------------------------------------------------------------------------------------
2009 2013 2015 2020
----------------------------------------------------------------------------------------------------------------
Costs........................................... $58,070,000 $60,559,000 $34,004,000 $37,543,000
[[Page 8511]]
Fuel Savings.................................... 15,347,000 83,506,000 102,523,000 109,589,000
----------------------------------------------------------------------------------------------------------------
D. Cost per Ton of Emissions Reduced
We have calculated the cost per ton of HC, benzene, total MSATs,
and PM emissions reductions associated with the fuel, vehicle, and PFC
programs using the costs described above and the emissions reductions
described in section IV. More detail on the costs, emissions
reductions, and cost per ton estimates can be found in the RIA. We have
calculated the costs per ton using the net present value of the
annualized costs of the program, including PFC gasoline fuel savings,
from 2009 through 2030 and the net present value of the annual emission
reductions through 2030. We have also calculated the cost per ton of
emissions reduced in the year 2030 using the annual costs and emissions
reductions in that year alone. This number represents the long-term
cost per ton of emissions reduced. For fuels, the cost per ton
estimates include costs and emission reductions that will occur from
all motor vehicles and nonroad engines fueled with gasoline.\216\
---------------------------------------------------------------------------
\216\ The proposed standards do not apply to nonroad engines,
since section 202(l) authorizes controls only for ``motor
vehicles,'' which term does not include nonroad vehicles (CAA
section 216(2)). However, we are reducing benzene in all gasoline,
including that used in nonroad equipment. Therefore, we are
including both the costs and the benzene emissions reductions
associated with the fuel used in nonroad equipment.
---------------------------------------------------------------------------
For vehicles and PFCs, we are establishing NMHC and HC standards,
respectively, which will also reduce benzene and other VOC-based
toxics. For vehicles, we are also expecting direct PM reductions due to
the NMHC standard.\217\ Section IV above provides an overview of how we
are estimating benzene and PM reductions resulting from the NMHC
standards for vehicles and benzene reductions resulting from the HC
standard for PFCs. We have not attempted to apportion costs across
these various pollutants for purposes of the cost per ton calculations
since there is no distinction in the technologies, or associated costs,
used to control the pollutants. Instead, we have calculated costs per
ton by assigning all costs to each individual pollutant. If we
apportioned costs among the pollutants, the costs per ton presented
here would be proportionally lowered depending on what portion of costs
were assigned to the various pollutants.
---------------------------------------------------------------------------
\217\ Again, although gasoline PM is not a mobile source air
toxic, the rule will result in emission reductions of gasoline PM,
which reductions are accounted for in our analysis.
---------------------------------------------------------------------------
The results for HC for vehicles and PFCs are provided in Table
VIII.D-1 using both a three percent and a seven percent social discount
rate. Again, this analysis assumes that all costs are assigned to HC
control. The discounted cost per ton of HC reduced for the final rule
as a whole would be $0 because the gasoline fuel savings from PFCs
offsets the costs of PFC and vehicle controls. The table presents these
as $0 per ton, rather than calculating a negative value that has no
clear meaning. For vehicles in 2030, the cost per ton is $0 because by
2030 all fixed costs have been recovered and there are no variable
costs estimated for the new vehicle program.\218\
---------------------------------------------------------------------------
\218\ We note that in determining whether the new vehicle
controls represent the greatest emissions reductions achievable
considering costs, we have considered the new cold-start standards
separately from any other new control program. Similarly, in
considering whether the new controls for PFCs represent the best
available control considering economic feasibility, we considered
the PFC standards separately from any other new control program.
---------------------------------------------------------------------------
The cost per ton estimates for each individual program are
presented separately in the tables below, and are part of the
justification for each of the programs. For informational purposes, we
also present the cost per ton for the three programs combined.
Table VIII.D-1.--HC Aggregate Cost Per Ton and Long-Term Annual Cost Per Ton
[$2003]
----------------------------------------------------------------------------------------------------------------
Discounted Discounted Long-Term cost
lifetime cost lifetime cost per ton in
per ton at 3% per ton at 7% 2030
----------------------------------------------------------------------------------------------------------------
Vehicles........................................................ $14 $18 $0
PFCs (without fuel savings)..................................... 240 270 190
PFCs (with fuel savings)........................................ 0 0 0
Combined (with fuel savings).................................... 0 0 0
----------------------------------------------------------------------------------------------------------------
The cost per ton of benzene reductions for fuels, vehicles, and
PFCs are shown in Table VIII.D-2 using the same methodology as noted
above for HC. The results are calculated by assigning all costs to
benzene control.
Table VIII.D-2.--Benzene Aggregate Cost per Ton and Long-Term Annual Cost Per Ton
[$2003]
----------------------------------------------------------------------------------------------------------------
Discounted Discounted Long-term cost
lifetime cost lifetime cost per ton in
per ton at 3% per ton at 7% 2030
----------------------------------------------------------------------------------------------------------------
Fuels........................................................... $22,400 $23,100 $22,500
Vehicles........................................................ 270 360 0
PFCs (without fuels savings).................................... 74,500 82,900 56,200
PFCs (with fuel savings)........................................ 0 0 0
[[Page 8512]]
Combined (with fuel savings).................................... 8,200 8,600 5,900
----------------------------------------------------------------------------------------------------------------
The cost per ton of reductions of all MSAT reductions for fuels,
vehicles, and PFCs are shown in Table VIII.D-3 using the same
methodology as noted above for HC and benzene. The results are
calculated by assigning all costs to MSAT control.
Table VIII.D-3.--MSAT Aggregate Cost per Ton and Long-Term Annual Cost Per Ton
[$2003]
----------------------------------------------------------------------------------------------------------------
Discounted Discounted Long-term cost
lifetime cost lifetime cost per ton in
per ton at 3% per ton at 7% 2030
----------------------------------------------------------------------------------------------------------------
Fuels........................................................... $22,400 $23,100 $22,500
Vehicles........................................................ 42 54 0
PFCs (without fuel savings)..................................... 2,800 3,100 2,200
PFCs (with fuel savings)........................................ 0 0 0
Combined (with fuel savings).................................... 1,700 1,800 1,100
----------------------------------------------------------------------------------------------------------------
We have also calculated a cost per ton for direct PM reductions for
vehicles. Again, this analysis assigns all related costs to direct PM
reductions.
Table VIII.D-4.--Direct PM Aggregate Cost per Ton and Long-Term Annual Cost Per Ton
[$2003]
----------------------------------------------------------------------------------------------------------------
Discounted Discounted Long-term cost
lifetime cost lifetime cost per ton in
per ton at 3% per ton at 7% 2030
----------------------------------------------------------------------------------------------------------------
Vehicles........................................................ $650 $870 $0
----------------------------------------------------------------------------------------------------------------
E. Benefits
This section presents our analysis of the health and environmental
benefits that will occur as a result of the final standards throughout
the period from initial implementation through 2030. In terms of
emission benefits, we expect to see significant reductions in mobile
source air toxics (MSATs) from the vehicle, fuel and PFC standards;
reductions in VOCs (an ozone and PM2.5 precursor) from the
cold temperature vehicle and PFC standards; and reductions in direct
PM2.5 from the cold temperature vehicle standards. When
translating emission benefits to health effects and monetized values,
however, we quantify only the PM-related benefits associated with the
cold temperature vehicle standards.
The reductions in PM2.5 from the cold temperature
vehicle standards will result in significant reductions in premature
deaths and other serious human health effects, as well as other
important public health and welfare effects. We estimate that in 2030,
the benefits we are able to monetize will be approximately $6.3 billion
using a 3 percent discount rate and $5.7 billion using a 7 percent
discount rate. Total social costs of the entire rule for the same year
(2030) are $400 million. Details on the costs of the final standards
are in section VIII.F. These estimates, and all monetized benefits
presented in this section, are in year 2003 dollars.
The PM2.5 benefits are scaled based on relative changes
in direct PM2.5 emissions between this rule and the proposed
Clean Air Nonroad Diesel (CAND) rule.\219\ As explained in Section
12.2.1 of the RIA for this rule, the PM2.5 benefits scaling
approach is limited to those studies, health impacts, and assumptions
that were used in the proposed CAND analysis. As a result, PM-related
premature mortality is based on the updated analysis of the American
Cancer Society cohort (ACS; Pope et al., 2002). However, it is
important to note that since the CAND rule, EPA's Office of Air and
Radiation (OAR) has adopted a different format for its benefits
analyses in which characterization of the uncertainty in the
concentration-response function is integrated into the main benefits
analysis. This new approach follows the recommendation of NRC's 2002
report ``Estimating the Public Health Benefits of Proposed Air
Pollution Regulations'' to begin moving the assessment of uncertainties
from its ancillary analyses into its main benefits presentation through
the conduct of probabilistic analyses. Within this context, additional
data sources are available, including a recent expert elicitation and
updated analysis of the Six-Cities Study cohort (Laden et al., 2006).
Please see the PM NAAQS RIA for an indication of the sensitivity of our
results to use of alternative concentration-response functions.
---------------------------------------------------------------------------
\219\ Due to time and resource constraints, EPA scaled the final
CAND benefits estimates from the benefits estimated for the CAND
proposal. The scaling approach used in that analysis, and applied
here, is described in the RIA for the final CAND rule.
---------------------------------------------------------------------------
We also demonstrate that the final standards will reduce cancer and
noncancer risk from reduced exposure to MSATs (as described in Section
IV of this preamble). However, we do not
[[Page 8513]]
translate this risk reduction into benefits. We also do not quantify
the benefits related to ambient reductions in ozone and
PM2.5 due to the VOC emission reductions associated with the
final standards. The following section describes in more detail why
these benefits are not quantified.
1. Unquantified Health and Environmental Benefits
This benefit analysis estimates improvements in health and human
welfare that are expected as a result of the final standards, and
monetizes those benefits. The benefits will come from reductions in
emissions of air toxics (including benzene, 1,3-butadiene,
formaldehyde, acetaldehyde, acrolein, naphthalene, and other air toxic
pollutants discussed in section III), ambient ozone (as a result of VOC
controls), and direct PM2.5 emissions.
While there will be benefits associated with air toxic pollutant
reductions, notably with regard to reductions in exposure and risk (see
section IV), we do not attempt to monetize those benefits. This is
primarily because available tools and methods to assess air toxics risk
from mobile sources at the national scale are not adequate for
extrapolation to incidence estimations or benefits assessment. The best
suite of tools and methods currently available for assessment at the
national scale are those used in the National-Scale Air Toxics
Assessment (NATA; these tools are discussed in Chapter 3 of the RIA).
The EPA Science Advisory Board specifically commented in their review
of the 1996 NATA that these tools were not yet ready for use in a
national-scale benefits analysis, because they did not consider the
full distribution of exposure and risk, or address sub-chronic health
effects.\220\ While EPA has since improved the tools, there remain
critical limitations for estimating incidence and assessing benefits of
reducing mobile source air toxics. We continue to work to address these
limitations, and we are exploring the feasibility of a quantitative
benefits assessment for air toxics through a benzene case study as part
of the revised study of ``The Benefits and Costs of the Clean Air Act''
(also known as the ``Section 812'' report).\221\ In this case study, we
are attempting to monetize the benefits of reduced cancer incidence,
specifically leukemia, and are not addressing other cancer or noncancer
endpoints.
---------------------------------------------------------------------------
\220\ Science Advisory Board. 2001. NATA--Evaluating the
National-Scale Air Toxics Assessment for 1996--an SAB Advisory.
http://www.epa.gov/ttn/atw/sab/sabrev.html.
\221\ The analytic blueprint for the Section 812 benzene case
study can be found at http://www.epa.gov/air/sect812/appendixi51203.pdf.
---------------------------------------------------------------------------
We also do not estimate the monetized benefits of VOC controls in
this benefits analysis. Though VOCs will be demonstrably reduced as a
result of the cold temperature vehicle standards, we assume that these
emissions will not have a measurable impact on ozone formation since
the standards will reduce VOC emissions at cold ambient temperatures
and ozone formation is primarily a warm ambient temperature issue. The
PFC controls will likely result in ozone benefits, though we do not
attempt to monetize those benefits. This is primarily due to the
magnitude of, and uncertainty associated with, the estimated changes in
ambient ozone associated with the final standards. In Section IV.C., we
discuss that the ozone modeling conducted for the final PFC standards
results in a net reduction in ambient ozone concentrations within the
modeled domain (37 Eastern states and the District of Columbia). The
net improvement is very small, however, and will likely lead to
negligible monetized benefits. Instead, we acknowledge that this
analysis may underestimate the benefits associated with reductions in
ozone precursor emissions achieved by the various standards. We discuss
these benefits qualitatively within the RIA.
The VOC reductions resulting from the cold temperature vehicle
standards and PFC standards will also likely reduce secondary
PM2.5 formation. However, we did not quantify the impacts of
these reductions on ambient PM2.5 or estimate any resulting
benefits. As described further below, we estimated PM benefits by
scaling from a previous analysis, and this analysis did not examine the
relationship between VOC reductions and ambient PM. As a result, we did
not quantify PM benefits associated with this rule's VOC reductions,
and we acknowledge that this analysis may therefore underestimate benefits.
Table VIII.E-1 lists each of the MSAT and ozone health and welfare
effects that remain unquantified because of current limitations in the
methods or available data. This table also includes the PM-related
health and welfare effects that also remain unquantified due to current
method and data limitations. Chapter 12 of the RIA for the final
standards provides a qualitative description of the health and welfare
effects not quantified in this analysis.
Table VIII.E-1.--Unquantified and Non-Monetized Effects
------------------------------------------------------------------------
Effects not included in primary
Pollutant/effects estimates--changes in:
------------------------------------------------------------------------
Ozone Health \a\....................... Premature mortality: short-term
exposures \b\.
Hospital admissions:
respiratory.
Emergency room visits for
asthma.
Minor restricted-activity days.
School loss days.
Asthma attacks.
Cardiovascular emergency room
visits.
Acute respiratory symptoms.
Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory
emergency room visits.
Exposure to UVb (+/-) \e\.
Ozone Welfare.......................... Decreased outdoor worker
productivity.
Agricultural yields for
--commercial forests.
--some fruits and vegetables.
--non-commercial crops.
Damage to urban ornamental
plants.
Impacts on recreational demand
from damaged forest
aesthetics.
Ecosystem functions.
Exposure to UVb (+/-) \e\.
PM Health \c\.......................... Premature mortality--short-term
exposures \d\.
Low birth weight.
Pulmonary function.
Chronic respiratory diseases
other than chronic bronchitis.
Non-asthma respiratory
emergency room visits.
Exposure to UVb (+/-) \e\.
PM Welfare............................. Visibility in many Class I
areas.
Residential and recreational
visibility in non-Class I
areas.
Soiling and materials damage.
Damage to ecosystem functions.
Exposure to UVb (+/-) \e\.
MSAT Health \f\........................ Cancer (benzene, 1,3-butadiene,
formaldehyde, acetaldehyde,
naphthalene).
Anemia (benzene).
Disruption of production of
blood components (benzene).
Reduction in the number of
blood platelets (benzene).
Excessive bone marrow formation
(benzene).
Depression of lymphocyte counts
(benzene).
Reproductive and developmental
effects (1,3-butadiene).
[[Page 8514]]
Irritation of eyes and mucus
membranes (formaldehyde).
Respiratory irritation
(formaldehyde).
Asthma attacks in asthmatics
(formaldehyde).
Asthma-like symptoms in non-
asthmatics (formaldehyde).
Irritation of the eyes, skin,
and respiratory tract
(acetaldehyde).
Upper respiratory tract
irritation and congestion
(acrolein).
Neurotoxicity (n-hexane,
toluene, xylenes).
MSAT Welfare \f\....................... Direct toxic effects to
animals.
Bioaccumulation in the food
chain.
Damage to ecosystem function.
Odor.
------------------------------------------------------------------------
\a\ In addition to primary economic endpoints, there are a number of
biological responses that have been associated with ozone health
effects including increased airway responsiveness to stimuli,
inflammation in the lung, acute inflammation and respiratory cell
damage, and increased susceptibility to respiratory infection.
\b\ Recent analyses provide evidence that short-term ozone exposure is
associated with increased premature mortality. As a result, EPA is
considering how to incorporate ozone mortality benefits into its
benefits analyses as a separate estimate of the number of premature
deaths that would be avoided due to reductions in ozone levels.
\c\ In addition to primary economic endpoints, there are a number of
biological responses that have been associated with PM health effects
including morphological changes and altered host defense mechanisms.
The public health impact of these biological responses may be partly
represented by our quantified endpoints.
\d\ While some of the effects of short-term exposures are likely to be
captured in the estimates, there may be premature mortality due to
short-term exposure to PM not captured in the cohort study upon which
the primary analysis is based. However, the PM mortality results
derived from the expert elicitation do take into account premature
mortality effects of short-term exposures.
\e\ May result in benefits or disbenefits.
\f\ The categorization of unquantified toxic health and welfare effects
is not exhaustive.
2. Quantified Human Health and Environmental Effects of the Final Cold
Temperature Vehicle Standard
In this section we discuss the benefits of the final cold
temperature vehicle standard related to reductions in directly emitted
PM2.5. To estimate PM2.5 benefits, we rely on a
benefits transfer technique. The benefits transfer approach uses as its
foundation the relationship between emission reductions and ambient
PM2.5 concentrations modeled across the contiguous 48 states
(and DC) for the Clean Air Nonroad Diesel (CAND) proposal.\222\ For a
given future year, we first calculate the ratio between CAND direct
PM2.5 emission reductions and direct PM2.5
emission reductions associated with the final cold temperature vehicle
control standard (cold temperature vehicle emission reductions/CAND
emission reductions). We multiply this ratio by the percent that direct
PM2.5 contributes towards population-weighted reductions in
total PM2.5 due to the CAND standards. This calculation
results in a ``benefits apportionment factor'' for the relationship
between direct PM emissions and primary PM2.5, which is then
applied to the BenMAP-based incidence and monetized benefits from the
CAND proposal. In this way, we apportion the results of the proposed
CAND analysis to its underlying direct PM emission reductions and scale
the apportioned benefits to reflect differences in emission reductions
between the two rules.\223\ This benefits transfer method is consistent
with the approach used in other recent mobile and stationary source
rules.\224\
---------------------------------------------------------------------------
\222\ See 68 FR 28327, May 23, 2003.
\223\ Note that while the final regulations also control VOCs,
which contribute to PM formation, the benefits transfer scaling
approach only scales benefits based on NOX,
SO2, and direct PM emission reductions. PM benefits will
likely be underestimated as a result, though we are unable to
estimate the magnitude of the underestimation.
\224\ See: Clean Air Nonroad Diesel final rule (69 FR 38958,
June 29, 2004); Nonroad Large Spark-Ignition Engines and
Recreational Engines standards (67 FR 68241, November 8, 2002);
Final Industrial Boilers and Process Heaters NESHAP (69 FR 55217,
September 13, 2004); Final Reciprocating Internal Combustion Engines
NESHAP (69 FR 33473, June 15, 2004); Final Clean Air Visibility Rule
(EPA-452/R-05-004, June 15, 2005); Ozone Implementation Rule
(documentation forthcoming).
---------------------------------------------------------------------------
Table VIII.E-2 presents the estimates of reduced incidence of
PM2.5-related health effects for the years 2020 and 2030 for
the final cold temperature vehicle control strategies. In 2030, we
estimate that PM2.5-related annual benefits will result in
approximately 880 fewer premature fatalities, 600 fewer cases of
chronic bronchitis, 1,600 fewer non-fatal heart attacks, and 900 fewer
hospitalizations (for respiratory and cardiovascular disease combined).
In addition, we estimate that the emission controls will reduce days of
restricted activity due to respiratory illness by about 600,000 days
and reduce work-loss days by about 100,000 days. We also estimate
substantial health improvements for children from reduced upper and
lower respiratory illness, acute bronchitis, and asthma attacks.
It is important to note that since the CAND rule, EPA's Office of
Air and Radiation (OAR) has adopted a different format for its benefits
analysis in which characterization of the uncertainty in the
concentration-response function is integrated into the main benefits
analysis. Within this context, additional data sources are available,
including a recent PM-related premature mortality expert elicitation
and updated analysis of the Six-Cities Study cohort (Laden et al.,
2006). Please see the PM NAAQS RIA for an indication of the sensitivity
of our results to use of alternative concentration-response functions.
---------------------------------------------------------------------------
\225\ Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D.
Krewski, K. Ito, and G.D. Thurston. 2002. ``Lung Cancer,
Cardiopulmonary Mortality, and Long-term Exposure to Fine
Particulate Air Pollution.'' Journal of American Medical Association
287:1132-1141.
\226\ Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997.
``The Relationship Between Selected Causes of Postneonatal Infant
Mortality and Particulate Infant Mortality and Particulate Air
Pollution in the United States.'' Environmental Health Perspectives
105(6):608-612.
Table VIII.E-2.--Estimated Annual Reductions in Incidence of Health
Effects Related to the Final Cold Temperature Vehicle Standard \a\
------------------------------------------------------------------------
2020 Annual 2030 Annual
Health effect incidence incidence
reduction reduction
------------------------------------------------------------------------
PM-Related Endpoints:
Premature Mortality \b\ Adult, age 30+ and 480 880
Infant, age < 1 year......................
[[Page 8515]]
Chronic bronchitis (adult, age 26 and 330 570
over)....................................
Non-fatal myocardial infarction (adult, 810 1,600
age 18 and over).........................
Hospital admissions--respiratory (all 260 530
ages) \c\................................
Hospital admissions--cardiovascular 210 390
(adults, age >18) \d\....................
Emergency room visits for asthma (age 18 350 610
years and younger).......................
Acute bronchitis, (children, age 8-12).... 780 1,400
Lower respiratory symptoms (children, age 9,300 16,000
7-14)....................................
Upper respiratory symptoms (asthmatic 7,000 12,000
children, age 9-18)......................
Asthma exacerbation (asthmatic children, 12,000 20,000
age 6-18)................................
Work loss days............................ 62,000 100,000
Minor restricted activity days (adults age 370,000 600,000
18-65)...................................
------------------------------------------------------------------------
\a\ Incidence is rounded to two significant digits. Estimates represent
benefits from the final rule nationwide, excluding Alaska and Hawaii.
\b\ PM-related adult mortality based upon the ACS cohort study (Pope et
al., 2002).\225\ PM-related infant mortality based upon studies by
Woodruff, Grillo, and Schoendorf, 1997.\226\ Due to analytical
constraints associated with the PM benefits scaling approach, we are
unable to present the premature mortality impacts associated with the
recent Six-Cities study (Laden et al., 2006) or the impacts associated
with the recent PM-related premature mortality expert elicitation
(IEc, 2006). Chapter 12.6 of the RIA discusses the implications these
new studies have on the benefits estimated for the final rule.
\c\ Respiratory hospital admissions for PM include admissions for
chronic obstructive pulmonary disease (COPD), pneumonia and asthma.
\d\ Cardiovascular hospital admissions for PM include total
cardiovascular and subcategories for ischemic heart disease,
dysrhythmias, and heart failure.
PM2.5 also has numerous documented effects on
environmental quality that affect human welfare. These welfare effects
include direct damages to property, either through impacts on material
structures or by soiling of surfaces, and indirect economic damages
through the loss in value of recreational visibility or the existence
value of important resources. Additional information about these
welfare effects can be found in Chapter 12 of the Regulatory Impact
Analysis.
3. Monetized Benefits
Table VIII.E-3 presents the estimated monetary value of reductions
in the incidence of those health effects we are able to monetize for
the final cold temperature vehicle standard. Total annual PM-related
health benefits are estimated to be approximately $6.3 or $5.7 billion
in 2030 (3 percent and 7 percent discount rate, respectively). These
estimates account for growth in real gross domestic product (GDP) per
capita between the present and 2030.
Table VIII.E-3 indicates with a ``B'' those additional health and
environmental benefits of the rule that we are unable to quantify or
monetize. These effects are additive to the estimate of total benefits,
and are related to the following sources:
? There are many human health and welfare effects associated
with PM, ozone, and toxic air pollutant reductions that remain
unquantified because of current limitations in the methods or available
data. A listing of the benefit categories that could not be quantified
or monetized in our benefit estimates are provided in Table VIII.E-1.
? The PM2.5 benefits scaled transfer approach,
derived from the Clean Air Nonroad Diesel rule, does not account for
VOCs as precursors to ambient PM2.5 formation. To the extent
that VOC emission reductions associated with the final regulations
contribute to reductions in ambient PM2.5, this analysis
does not capture the related health and environmental benefits of those
changes.
? The PM air quality model only captures the benefits of air
quality improvements in the 48 states and DC; PM benefits for Alaska
and Hawaii are not reflected in the estimate of benefits.
Table VIII.E-3.--Estimated Annual Monetary Value of Reductions in Incidence of Health and Welfare Effects
Related to the Final Cold Temperature Vehicle Standard
(Millions of 2003$) a,b
----------------------------------------------------------------------------------------------------------------
2020 estimated 2030 estimated
Health effect Pollutant value of value of
reductions reductions
----------------------------------------------------------------------------------------------------------------
PM-Related Premature mortality c,d Adult, 30+
years and Infant, < 1 year:
3 percent discount rate................... PM2.5........................... $3,100 $5,800
7 percent discount rate................... ................................ 2,800 5,200
Chronic bronchitis (adults, 26 and over)...... PM2.5........................... 150 260
Non-fatal acute myocardial infarctions:
3 percent discount rate................... ................................ 79 150
7 percent discount rate................... PM2.5........................... 76 140
Hospital admissions for respiratory causes.... PM2.5........................... 4.7 10
Hospital admissions for cardiovascular causes. PM2.5........................... 5.0 9.1
Emergency room visits for asthma.............. PM2.5........................... 0.11 0.20
Acute bronchitis (children, age 8-12)......... PM2.5........................... 0.32 0.56
Lower respiratory symptoms (children, age 7- PM2.5........................... 0.16 0.29
14).
Upper respiratory symptoms (asthma, age 9-11). PM2.5........................... 0.20 0.35
Asthma exacerbations.......................... PM2.5........................... 0.56 1.0
[[Page 8516]]
Work loss days................................ PM2.5........................... 9.1 14
Minor restricted activity days (MRADs)........ PM2.5........................... 21 35
Monetized Total\e\
Base estimate:
3 percent discount rate................... PM2.5........................... 3,300+ B 6,300+ B
7 percent discount rate................... ................................ 3,000+ B 5,700+ B
----------------------------------------------------------------------------------------------------------------
\a\ Dollars are rounded to two significant digits. The PM estimates represent benefits from the final rule
across the contiguous United States.
\b\ Monetary benefits adjusted to account for growth in real GDP per capita between 1990 and the analysis year
(2020 or 2030).
\c\ Valuation of premature mortality based on long-term PM exposure assumes discounting over the SAB recommended
20-year segmented lag structure described in the Regulatory Impact Analysis for the Final Clean Air Interstate
Rule (March 2005). Results show 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines
for preparing economic analyses (US EPA, 2000 and OMB, 2003).227,228
\d\ Adult mortality based upon the ACS cohort study (Pope et al., 2002). Infant mortality based upon studies by
Woodruff, Grillo, and Schoendorf, 1997. Due to analytical constraints associated with the PM benefits scaling
approach, we are unable to present the premature mortality impacts associated with the recent Six-Cities study
(Laden et al., 2006) study or the impacts associated with the recent PM-related premature mortality expert
elicitation (IEc, 2006). Chapter 12.6 of the RIA discusses the implications these new studies have on the
benefits estimated for the final rule.
\e\ B represents the monetary value of health and welfare benefits not monetized. A detailed listing is provided
in Table VIII.E-1.
4. What Are the Significant Limitations of the Benefit Analysis?
The most significant limitation of this analysis is our inability
to quantify a number of potentially significant benefit categories
associated with improvements in air quality that would result from the
final standards. Most notably, we are unable to estimate the benefits
from reduced air toxics exposures because the available tools and
methods to assess mobile source air toxics risk at the national scale
are not adequate for extrapolation to incidence estimations or benefits
assessment. We also do not quantify ozone benefits associated with the
final PFC standards, despite the fact that there are net benefits, when
population-weighted, in the ozone design value metric across the
modeled domain (see section IV.C). We do not quantify these benefits
because of their magnitude and the uncertainty associated with them.
---------------------------------------------------------------------------
\227\ U.S. Environmental Protection Agency, 2000, Guidelines for
Preparing Economic Analyses.
http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html.
\228\ Office of Management and Budget, The Executive Office of
the President, 2003. Circular A-4. http://www.whitehouse.gov/omb/circlars.
---------------------------------------------------------------------------
More generally, every benefit-cost analysis examining the potential
effects of a change in environmental protection requirements is limited
to some extent by data gaps, limitations in model capabilities (such as
geographic coverage), and uncertainties in the underlying scientific
and economic studies used to configure the benefit and cost models.
Deficiencies in the scientific literature often result in the inability
to estimate quantitative changes in health and environmental effects.
Deficiencies in the economics literature often result in the inability
to assign economic values even to those health and environmental
outcomes which can be quantified. These general uncertainties in the
underlying scientific and economics literature, which can cause the
valuations to be higher or lower, are discussed in detail in the RIA
and its supporting references. Key uncertainties that have a bearing on
the results of the benefit-cost analysis of the final standards include
the following:
? The exclusion of potentially significant and unquantified
benefit categories (such as health, odor, and ecological benefits of
reduction in air toxics, ozone, and PM);
? Errors in measurement and projection for variables such as
population growth;
? Uncertainties in the estimation of future year emissions
inventories and air quality;
? Uncertainties associated with the scaling of the PM
results of the modeled benefits analysis to the final standards,
especially regarding the assumption of similarity in geographic
distribution between emissions and human populations and years of analysis;
? Uncertainty in the estimated relationships of health and
welfare effects to changes in pollutant concentrations including the
shape of the C-R function, the size of the effect estimates, and the
relative toxicity of the many components of the PM mixture;
? Uncertainties in exposure estimation; and
? Uncertainties associated with the effect of potential
future actions to limit emissions.
As Table VIII.E-3 indicates, total benefits are driven primarily by
the reduction in premature fatalities each year. Elaborating on the
list of uncertainties above, some key assumptions underlying the
primary estimate for the premature mortality category include the
following:
1. Inhalation of fine particles is causally associated with
premature death at concentrations near those experienced by most
Americans on a daily basis. Although biological mechanisms for this
effect have not yet been completely established, the weight of the
available epidemiological, toxicological, and experimental evidence
supports an assumption of causality. The impacts of including a
probabilistic representation of causality were explored in the expert
elicitation-based results of the recently published PM NAAQS RIA.
Because the analysis of the final cold temperature vehicle standard is
constrained to the studies included in the CAND PM benefits scaling
approach, we are unable to conduct the same analysis of expert
elicitation-based mortality incidence for the final standards.\229\
However, we qualitatively describe the expert elicitation-based
mortality results associated with the final PM NAAQS to provide an
indication of the sensitivity of our PM-related premature mortality
results to use of alternative
[[Page 8517]]
concentration-response functions. We present this discussion in the RIA.
---------------------------------------------------------------------------
\229\ The scaling approach relies on the incidence and valuation
estimates derived from the studies available at the time of the CAND
analysis. Incidence estimates and monetized benefits derived from
new information, including mortality derived from the full expert
elicitation, are not available for scaling. Please refer to section
2 of this preamble and Chapter 12 of the RIA for more information
about the benefits scaling approach.
---------------------------------------------------------------------------
2. Since the publication of CAIR and CAND, a follow up to the
Harvard Six-Cities study on premature mortality was published (Laden et
al., 2006 based on Dockery et al., 1993),230, 231 which both
confirmed the effect size from the first study and provided additional
evidence that reductions in PM2.5 directly result in reductions in the
risk of premature death. The impacts of including this study in the
primary analysis were explored in the results of the recently published
PM NAAQS RIA. Because the analysis of the final cold temperature
vehicle standard is constrained to the studies included in the CAND PM
benefits scaling approach, we are unable to characterize PM-related
mortality based on Laden et al. However, we discuss the implications of
these results in the RIA for the final standards.
---------------------------------------------------------------------------
\230\ Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery.
2006. Reduction in Fine Particulate Air Pollution and Mortality.
American Journal of Respiratory and Critical Care Medicine. 173: 667-672.
\231\ Dockery, D.W., C.A. Pope, X.P. Xu, J.D. Spengler, J.H.
Ware, M.E. Fay, B.G. Ferris, and F.E. Speizer. 1993. ``An
Association between Air Pollution and Mortality in Six U.S.
Cities.'' New England Journal of Medicine 329(24):1753-1759.
---------------------------------------------------------------------------
3. All fine particles, regardless of their chemical composition,
are equally potent in causing premature mortality. This is an important
assumption, because PM produced via transported precursors emitted from
vehicles at cold temperatures may differ significantly from PM
precursors released from electric generating units and other industrial
sources. However, no clear scientific grounds exist for supporting
differential effects estimates by particle type.
4. The concentration-response function for fine particles is
approximately linear within the range of ambient concentrations under
consideration. Thus, the estimates include health benefits from
reducing fine particles in areas with varied concentrations of PM,
including both regions that may be in attainment with PM2.5
standards and those that are at risk of not meeting the standards.
Taking into account these uncertainties, we believe this benefit-
cost analysis provides a conservative estimate of the expected economic
benefits of the final standards for cold temperature vehicle control in
future years because of the exclusion of potentially significant
benefit categories. Acknowledging benefits omissions and uncertainties,
we present a best estimate of the total benefits based on our
interpretation of the best available scientific literature and methods.
Furthermore, our analysis reflects many methodological improvements
that were incorporated into the analysis of the final Clean Air
Interstate Rule (CAIR), including a revised value of a statistical
life, a revised baseline rate of future mortality, and a revised
mortality lag assumption. Details of these improvements can be found in
the RIA for this rule and in the final CAIR rule RIA.\232\ Once again,
however, it should be noted that since the CAIR rule, EPA's Office of
Air and Radiation (OAR) has adopted a different format for its benefits
analysis in which characterization of uncertainty is integrated into
the main benefits analysis. Please see the PM NAAQS RIA for an
indication of the uncertainty present in the base estimate of benefits
and the sensitivity of our results to the use of alternative
concentration-response functions.
---------------------------------------------------------------------------
\232\ See Chapter 4 of the Final Clean Air Interstate Rule RIA
(http://www.epa.gov/cair) for a discussion of EPA's ongoing efforts
to address the NAS recommendations in its regulatory analyses.
---------------------------------------------------------------------------
In contrast to the additional benefits of the final standards
discussed above, it is also possible that this rule will result in
disbenefits in some areas of the United States. The effects of ozone
and PM on radiative transfer in the atmosphere can lead to effects of
uncertain magnitude and direction on the penetration of ultraviolet
light and climate. Ground level ozone makes up a small percentage of
total atmospheric ozone (including the stratospheric layer) that
attenuates penetration of ultraviolet--b (UVb) radiation to the ground.
EPA's past evaluation of the information indicates that potential
disbenefits would be small, variable, and with too many uncertainties
to attempt quantification of relatively small changes in average ozone
levels over the course of a year.\233\ EPA's most recent provisional
assessment of the currently available information indicates that
potential but unquantifiable benefits may also arise from ozone-related
attenuation of UVb radiation.\234\ In addition, EPA believes that we
are unable to quantify any net climate-related disbenefit or benefit
associated with the combined ozone and PM reductions in this rule.
---------------------------------------------------------------------------
\233\ EPA, 2005. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (First External Review Draft). January.
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=114523.
\234\ EPA, 2005. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Second External Review Draft). August.
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=137307.
---------------------------------------------------------------------------
5. How Do the Benefits Compare to the Costs of The Final Standards?
The final rule provides three separate provisions that reduce air
toxics emissions from mobile sources: cold temperature vehicle
controls, a PFC emissions control program, and a control program
limiting benzene in gasoline. A full appreciation of the overall
economic consequences of these provisions requires consideration of the
benefits and costs expected to result from each standard, not just
those that could be expressed here in dollar terms. As noted above, due
to limitations in data availability and analytical methods, our
benefits analysis only monetizes the PM2.5 benefits from
direct PM emission reductions associated with the cold temperature
standards. There are a number of health and environmental effects
associated with the final standards that we were unable to quantify or
monetize (see Table VIII.E-1).
Table VIII.E-4 contains the estimates of monetized benefits of the
final cold temperature vehicle standards only and estimated social
welfare costs for all of the final control programs.\235\ The annual
social welfare costs of all provisions of the final rule are described
more fully in Section VIII.F. It should be noted that the estimated
social welfare costs for the vehicle program contained in this table
are for 2019. The 2019 vehicle program costs are included for
comparison purposes only and are therefore not included in the total
2020 social costs. There are no compliance costs associated with the
vehicle program after 2019; as explained elsewhere in this preamble,
the vehicle compliance costs are primarily R&D and facilities costs
that are expected to be recovered by manufacturers over the first ten
years of the program.
---------------------------------------------------------------------------
\235\ Social costs represent the welfare costs of the rule to
society. These social costs do not consider transfer payments (such
as taxes) that are simply redistributions of wealth.
---------------------------------------------------------------------------
The results in Table VIII.E-4 suggest that the 2020 monetized
benefits of the cold temperature vehicle standards are greater than the
expected social welfare costs of that program in 2019. Specifically,
the annual benefits of the program will be approximately $3,300 + B
million or $3,000 + B million annually in 2020 (using a 3 percent and 7
percent discount rate in the benefits analysis, respectively), compared
to estimated social welfare costs of approximately $10.6 million in the
last year of the program (2019). These benefits are expected to
increase to $6,300 + B million or $5,700 + B million annually in 2030
(using a 3 percent and
[[Page 8518]]
7 percent discount rate in the benefits analysis, respectively), even
as the social welfare costs of that program fall to zero. Table VIII.E-
4 also presents the costs of the other rule provisions: a PFC emissions
control program and a control program limiting benzene in gasoline.
Though we are unable to present the benefits associated with these two
programs, the benefits associated with the final cold temperature
vehicle standards alone outweigh the costs of all three rule provisions
combined.
Table VIII.E-4.--Summary of Annual Benefits of the Final Cold
Temperature Vehicle Standards and Costs of All Provisions of the Final
Standards a
[Millions of 2003 dollars]
------------------------------------------------------------------------
2020 (Millions of 2030 (Millions of
Description 2003 dollars) 2003 dollars)
------------------------------------------------------------------------
Estimated Social Welfare Costs b
Cold Temperature Vehicle $10.6 c........... $0
Standards.
PFC Standards............... $37.5............. $45.7
Fuel Standards d............ $402.6............ $445.8
Total....................... $440.1............ $491.5
Fuel Savings................ -$80.7............ -$91.5
Net Social Welfare Costs $359.4............ $400.0
------------------------------------------------------------------------
Total PM2.5-Related Health
Benefits of the
Cold Temperature Vehicle
Standards e
3 percent discount rate..... $3,300 + B f...... $6,300 + B f
7 percent discount rate..... $3,000 + B f...... $5,700 + B f
------------------------------------------------------------------------
a All estimates are rounded to two significant digits and represent
annualized benefits and costs anticipated for the years 2020 and 2030,
except where noted. Totals may not sum due to rounding.
b Note that costs are the annual costs of reducing all pollutants
associated with each provision of the final MSAT control package in
2020 and 2030 (unless otherwise noted). To estimate fixed costs
associated with the vehicle standards, we use a 7 percent average
before-tax rate of return over 5 years to amortize the capital fixed
costs. For the fuel standards, we use a 7 percent before-tax rate of
return over 15 years to amortize the capital costs. Note that by 2020,
PFC container standard costs are only variable and do not use a rate
of return assumption. See Chapters 8 and 9 for discussion of the
vehicle and fuel standard costs, respectively. In Chapter 13, however,
we do use both a 3 percent and 7 percent social discount rate to
calculate the net present value of total social costs consistent with
EPA and OMB guidelines for preparing economic analyses (US EPA, 2000
and OMB, 2003).236, 237
c These costs are for 2019; the vehicle program compliance costs
terminate after 2019 and are included for illustrative purposes. They
are not included in the total social welfare cost sum for 2020.
d Our modeling for the total costs of the proposed gasoline benzene
program included participation by California refineries (achieving
benzene reductions below the 0.62 proposed benzene standard--thus
generating credits), since it was completed before we decided that
California gasoline would not be covered by the program. For the final
rule, we exclude California refineries from the analysis. By excluding
California refineries, other higher cost refineries will have to
comply in their place, slightly increasing the costs for the program.
e Annual benefits reflect only direct PM reductions associated with the
cold temperature vehicle standards. Annual benefits analysis results
reflect the use of a 3 percent and 7 percent discount rate in the
valuation of premature mortality and nonfatal myocardial infarctions,
consistent with EPA and OMB guidelines for preparing economic analyses
(US EPA, 2000 and OMB, 2003). Valuation of premature mortality based
on long-term PM exposure assumes discounting over the SAB recommended
20-year segmented lag structure described in the Regulatory Impact
Analysis for the Final Clean Air Interstate Rule (March 2005).
Valuation of nonfatal myocardial infarctions (MI) assumes discounting
over a 5-year period, reflecting lost earnings and direct medical
costs following a nonfatal MI. Note that we do not calculate a net
present value of benefits associated with the cold temperature vehicle
standards.
f Not all possible benefits or disbenefits are quantified and monetized
in this analysis. B is the sum of all unquantified benefits and
disbenefits. Potential benefit categories that have not been
quantified and monetized are listed in Table VIII.E-1.
F. Economic Impact Analysis
We prepared an Economic Impact Analysis (EIA) to estimate the
economic impacts of this rule on the portable fuel container (PFC),
gasoline fuel, and light-duty vehicle markets. In this section we
briefly describe the Economic Impact Model (EIM) we developed to
estimate both the market-level changes in price and outputs for
affected markets and the social costs of the program and their
distribution across affected stakeholders. We also present the results
of our analysis.
---------------------------------------------------------------------------
\236\ U.S. Environmental Protection Agency, 2000. Guidelines for
Preparing Economic Analyses.
http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html.
\237\ Office of Management and Budget, The Executive Office of
the President, 2003. Circular A-4. http://www.whitehouse.gov/omb/circulars.
---------------------------------------------------------------------------
We estimate the net social costs of the program to be about $359.4
million in 2020. This estimate reflects the estimated costs associated
with compliance with the gasoline, PFC, and vehicle controls and the
expected gasoline fuel savings from better evaporative controls on
PFCs. The results of the economic impact modeling performed for the
gasoline fuel and PFC control programs suggest that the social costs of
those two programs are expected to be about $440.1 million in 2020,
with consumers of these products expected to bear about 58.4 percent of
these costs. We estimate gasoline fuel savings of about $80.7 million
in 2020, which will accrue to consumers. There are no social costs
associated with the vehicle program in 2020 (these accrue only in the
10-year period from 2010 through 2019). These estimates, and all costs
presented in this section, are in year 2003 dollars.
With regard to market-level impacts in 2020, the maximum price
increase for gasoline fuel is expected to be about 0.3 percent (0.5
cents per gallon), for PADD 5. The price of PFCs is expected to
increase by about 1.9 percent ($0.20 per can) in areas that already
have PFC requirements and 32.5 percent ($1.52 per can) in areas that do not.
Detailed descriptions of the EIM, the model inputs, modeling
results, and several sensitivity analyses can be found in Chapter 13 of
the Regulatory Impact Analysis prepared for this rule.
1. What Is an Economic Impact Analysis?
An Economic Impact Analysis (EIA) is prepared to inform decision
makers about the potential economic consequences of a regulatory
action. The analysis consists of estimating the social costs of a
regulatory program and the distribution of these costs across
stakeholders. These estimated social costs can then be compared with
estimated social benefits (as presented
[[Page 8519]]
in Section VIII.E). As defined in EPA's Guidelines for Preparing
Economic Analyses, social costs are the value of the goods and services
lost by society resulting from a) the use of resources to comply with
and implement a regulation and b) reductions in output.\238\ In this
analysis, social costs are explored in two steps. In the market
analysis, we estimate how prices and quantities of goods affected by
the emission control program can be expected to change once the program
goes into effect. In the economic welfare analysis, we look at the
total social costs associated with the program and their distribution
across stakeholders.
---------------------------------------------------------------------------
\238\ EPA Guidelines for Preparing Economic Analyses, EPA 240-R-
00-003, September 2000, p 113. A copy of this document can be found at
http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html#download.
---------------------------------------------------------------------------
2. What Is the Economic Impact Model?
The Economic Impact Model (EIM) is a behavioral model developed to
estimate price and quantity changes and total social costs associated
with the emission controls set out in this rule. The EIM simulates how
producers and consumers of affected products can be expected to respond
to an increase in production costs associated with compliance with the
emission control program. In this EIM, compliance costs are directly
borne by producers of affected goods. Depending on the producers' and
consumers' sensitivity to price changes, producers may be able to pass
some or all of these compliance costs on to the consumers of these
goods in the form of higher prices. Consumers adjust their consumption
of affected goods in response to these price changes. This information
is passed back to the producers in the form of purchasing decisions.
The EIM takes these behavioral responses into account to estimate new
market equilibrium quantities and prices for all modeled sectors and
the resulting distribution of social costs across these stakeholders
(producers and consumers).
3. What Economic Sectors Are Included in this Economic Impact Analysis?
There are three economic sectors affected by the control programs
described in this rule: PFCs, gasoline fuel, and light-duty vehicles.
In this Economic Impact Analysis we model only the impacts on the PFC
and gasoline fuel markets. We did not model the impacts on the light-
duty vehicle market. This is because the compliance costs for the
vehicle program are expected to be very small, less than $1 per vehicle
and, even if passed on entirely, are unlikely to affect producer or
consumer behavior. Therefore, we do not expect these controls to affect
the quantity of vehicles produced or their prices. At the same time,
however, the light-duty vehicle compliance costs are a cost to society
and should be included in the economic welfare analysis. We do this by
adding the vehicle program engineering compliance cost estimates to the
estimated social costs of the gasoline and PFC programs.
With regard to the gasoline fuel and PFC markets, we model the
impacts on residential users of these products. This means that we
focus the analysis on the use of these products for personal
transportation (gasoline fuel) or residential lawns and garden care or
recreational uses (PFCs) and do not separately model how the costs of
complying with the standards may affect the production of goods and
services that use gasoline fuel or PFCs as production inputs. We
believe this approach is reasonable because the commercial share of the
end-user markets for both gasoline fuel and PFCs is relatively
small.239, 240 In addition, for most commercial users the
share of the cost of these products to total production costs is also
small (e.g., the cost of a PFC is only a very small part of the total
production costs for an agricultural or construction firm). Therefore,
a price increase of the magnitude anticipated for this control program
is not expected to have a noticeable impact on prices or quantities of
goods produced using these inputs (e.g., agricultural product or buildings).
---------------------------------------------------------------------------
\239\ The U.S Department of Energy estimates that about 92
percent of gasoline used in the United States for transportation is
used in light-duty vehicles. About 6 percent is used for commercial
or industrial transportation, and the remaining 2 percent is used in
recreational marine vessels. See U.S Department of Energy, Energy
Information Administration, 2004. ``Annual Energy Outlook 2004 with
projections to 2025.'' Last updated June 2, 2004. Table A-2 and
Supplemental Table 34. http://www.eia.doe.gov/oiaf/aeoref_tab.html.
\240\ A recent study by CARB (1999) found that 94 percent of
portable fuel containers in California were used by residential
households California Environmental Protection Agency, Air Resources
Board (CARB) 1999. See ``Hearing Notice and Staff Report, Initial
Statement of Reasons for Proposed Rule Making Public Hearing to
Consider the Adoption of Portable Fuel Container Spillage Control
Regulation.'' Sacrament, CA: California Environmental Protection
Agency, Air Resources Board (CARB). A copy of this document is
available at http://www.arb.ca.gov/regact/spillcon/isor.pdf.
---------------------------------------------------------------------------
With regard to the gasoline fuel analysis, it should be noted that
this EIA does not include California fuels in the market analysis.
California currently has state-level controls that address air toxics
from gasoline. Also, consistent with the cost analysis, the economic
impact analysis does not distinguish between reformulated and
conventional gasoline fuels.
The EIM models the economic impacts on two PFC markets (states that
currently have requirements for PFCs and those that do not), and four
gasoline fuel markets (PADDs 1+3, PADD 2, PADD 4, PADD 5). The markets
included in this EIA are described in more detail in Chapter 13 of the
RIA for this rule.
In the EIM, the gasoline fuel and PFC markets are not linked (there
is no feedback mechanism between the PFC and gasoline fuel model
segments). This is because these two sectors represent different
aspects of fuel consumption (fuel storage and fuel production) and
production and consumption of PFCs is not expected to have an impact on
the production and supply of gasoline, and vice versa. Production and
consumption of each of these products are the result of other factors
that have little cross-over impacts (the need for fuel storage; the
need for personal transportation).
4. What Are the Key Features of the Economic Impact Model?
A detailed description of the features of the EIM and the data used
in the analysis is provided in Chapter 13 of the RIA prepared for this
rule. The model methodology is firmly rooted in applied microeconomic
theory and was developed following the methodology set out in the
OAQPS's Economic Analysis Resource Document.\241\
---------------------------------------------------------------------------
\241\ U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics
Group, OAQPS Economic Analysis Resource Document, April 1999. A copy
of this document can be found at http://www.epa.gov/ttn/ecas/econdata/Rmanual2/.
---------------------------------------------------------------------------
The EIM is a computer model comprised of a series of spreadsheet
modules that simulate the supply and demand characteristics of the
affected markets. The initial market equilibrium conditions are shocked
by applying the compliance costs for the control program to the supply
side of the markets (this is done by shifting the relevant supply
curves by the amount of the compliance costs). The model equations can
be analytically solved for equilibrium prices and quantities for the
markets with the regulatory program and these new prices and quantities
are used to estimate the social costs of the model and how those costs
are shared among affected markets.
The EIM is a partial equilibrium, intermediate-run model that
assumes perfect competition in the relevant markets. As explained in
EPA's Guidelines for Preparing Economic Analyses, ``partial
equilibrium'' means that the model considers markets in
[[Page 8520]]
isolation and that conditions in other markets are assumed either to be
unaffected by a policy or unimportant for social cost estimation.\242\
The use of the intermediate run means that some factors of production
are fixed and some are variable. In very short analyses, all factors of
production would be assumed to be fixed, leaving the producers with no
means to respond to the increased production costs associated with the
regulation (e.g., they cannot adjust labor or capital inputs). Under
this time horizon, the costs of the regulation fall entirely on the
producer. In the long run, all factors of production are variable and
producers can adjust production in response to cost changes imposed by
the regulation (e.g., using a different labor/capital mix). In the
intermediate run there is some resource immobility which may cause
producers to suffer producer surplus losses, but they can also pass
some of the compliance costs to consumers.
---------------------------------------------------------------------------
\242\ EPA Guidelines for Preparing Economic Analyses, EPA 240-R-
00-003, September 2000, p. 125-6.
---------------------------------------------------------------------------
The perfect competition assumption is widely accepted economic
practice for this type of analysis, and only in rare cases are other
approaches used.\243\ It should be noted that the perfect competition
assumption is not primarily about the number of firms in a market. It
is about how the market operates: the nature of the competition among
firms. Indicators that allow us to assume perfect competition include
absence of barriers to entry, absence of strategic behavior among firms
in the market, and product differentiation.
---------------------------------------------------------------------------
\243\ See, for example, EPA Guidelines for Preparing Economic
Analyses, EPA 240-R-00-003, September 2000, p 126.
---------------------------------------------------------------------------
With regard to the fuel market, the Federal Trade Commission (FTC)
has developed an approach to ensure competitiveness in gasoline fuel
markets. It reviews oil company mergers and frequently requires
divestiture of refineries, terminals, and gas stations to maintain a
minimum level of competition. This is discussed in more detail in the
industry profile prepared for this rule.\244\
---------------------------------------------------------------------------
\244\ Section 3 Industry Organization, ``Characterizing Gasoline
Markets: a Profile,'' Final Report, prepared for EPA by RTI, August 2005.
---------------------------------------------------------------------------
With regard to the PFC market, the small number of firms in the
market is offset by several features of this market. Because PFCs are
compact and lightweight, they are easy to transport far from their
place of manufacture. This means that production is not limited to
local producers. Although they vary by size and material, consumers are
likely to view all PFCs designed for storing a particular fuel
(gasoline, diesel fuel, kerosene) as good substitutes for the storage
of that particular fuel. Because the products are similar enough to be
considered homogeneous (e.g., perfectly substitutable), consumers can
shift their purchases from one manufacturer to another. There are only
minimal technical barriers to entry that would prevent new firms from
freely entering the market, since manufacturing is based on well-known
plastic processing methods. In addition, there is significant excess
capacity, enabling competitors to respond quickly to changes in price.
Excess production capacity in the general container manufacturing
market also means that manufacturers could potentially switch their
product lines to compete in this segment of the market, often without a
significant investment. In addition, there is no evidence of high
levels of strategic behavior in the price and quantity decisions of the
firms. Finally, it should be noted that contestable market theory
asserts that oligopolies and even monopolies will behave very much like
firms in a competitive market if manufacturers have extra production
capacity and this capacity could allow them to enter the market
costlessly (i.e., there are no sunk costs associated with this kind of
market entry or exit).\245\ As a result of all of these conditions,
producers and consumers in the PFC market are expected to take the
market price as given when making their production and consumption
choices and the market can be modeled as a competitive market even
though the number of producers is small.
---------------------------------------------------------------------------
\245\ A monopoly or firms in oligopoly may not behave as
neoclassical economic theories of the firm predict because they may
be concerned about new entrants to the market. If super-normal
profits are earned, potential competitors may enter the market. To
respond to this threat, existing firm(s) in the market will keep
prices and output at a level where only normal profits are made,
setting price and output levels at or close to the competitive price
and output. See Chapter 13 of the RIA for more information, Section 13.2.3.
---------------------------------------------------------------------------
5. What Are the Key Model Inputs?
Key model inputs for the EIM are the behavioral parameters,
compliance costs estimates, and market equilibrium quantities and prices.
The EIM is a behavioral model. The estimated social costs of this
emission control program are a function of the ways in which producers
and consumers of the PFC and gasoline fuel affected by the standards
change their behavior in response to the costs incurred in complying
with the standards. These behavioral responses are incorporated in the
EIM through the price elasticity of supply and demand (reflected in the
slope of the supply and demand curves), which measure the price
sensitivity of consumers and producers. The price elasticities used in
this analysis are described in Chapter 13 of the RIA. The gasoline
elasticities were obtained from the literature and are -0.2 for demand
and 0.2 for supply. This means that both the quantity supplied and
demanded are expected to be fairly insensitive to price changes and
that increases in prices are not expected to cause sales to fall or
production to increase by very much. Because we were unable to find
published supply and demand elasticities for the PFC market, we
estimated these parameters using the procedures described in Chapter 13
of the RIA. This approach yielded a demand elasticity of -0.01 and a
supply elasticity of 1.5. The estimated demand elasticity is nearly
perfectly inelastic (equal to zero), which means that changes in price
are expected to have very little effect on the quantity of PFCs
demanded. However, supply is fairly elastic, meaning producers are
expected to respond to a change in price. Therefore, consumers are
expected to bear more of the burden of PFC regulatory control costs
than producers.
Initial market equilibrium conditions are simulated using the same
current year sales quantities and growth rates used in the engineering
cost analysis. The initial equilibrium prices for PFCs and gasoline
fuel were obtained from industry sources and published government data.
The initial equilibrium market conditions are shocked by applying the
engineering compliance cost estimates described earlier in this
section. Although both the PFC and gasoline fuel markets are
competitive markets, the model is shocked by applying the sum of
variable and fixed costs. Two sets of compliance costs are used in the
PFC market analysis, reflecting states with existing controls and
states without existing controls. The compliance costs used to shock
the gasoline fuel market are based on an average total cost (variable +
fixed) analysis. An explanation for this approach can be found in
Section 13.2.4.1 of the RIA prepared for this rule. These gasoline fuel
compliance costs differ across PADDs but are the same across years.
Because California already has existing gasoline fuel controls, fuel
volumes for that state are not included in the market analysis.
Additional costs that need to be considered in the EIM are the
gasoline fuel savings associated with the PFC controls and the costs of
the light-duty vehicle controls. The PFC controls are
[[Page 8521]]
expected to reduce gasoline evaporative emissions from fuel storage,
leading to gasoline fuel savings for users of these containers. These
gasoline fuel savings are not included in the market analysis for this
economic impact analysis because these savings are not expected to
affect consumer decisions with respect to the purchase of new
containers. Gasoline fuel savings are included in the social cost
analysis, however, because they are a savings that accrues to society.
The estimated gasoline fuel savings are added to the estimated social
costs as a separate line item. As noted above, the economic impacts of
the light-duty vehicle controls are not modeled in the EIM. Instead,
the estimated engineering compliance costs are used as a proxy, and are
also added into the estimated social costs as a separate line item.
The EIM relies on the estimated compliance costs for the PFC and
gasoline fuel programs described elsewhere in this preamble. Thus, the
EIM reflects cost savings associated with ABT or other flexibility
programs to the extent they are included in the estimated compliance costs.
6. What Are the Results of the Economic Impact Modeling?
Using the model and data described above, we estimated the economic
impacts of the rule. The results of our modeling for selected years are
summarized in this section. The year 2009 is presented because that is
the first year in which both the PFC and the gasoline programs are in
effect (the PFC program begins in 2009; the gasoline fuel program goes
into effect January 1, 2011 but the compliance cost analysis includes a
phase-in starting in 2007 that ends May 2015). The year 2012 is
presented because it is a high cost year due to the way the fuel
program compliance costs were estimated.\246\ The year 2015 is
presented because beginning with that year compliance costs are
stabilized for future years for both the gasoline and PFC programs (the
vehicle program compliance costs continue for five more years).
Detailed results for all years are included in the appendices to
Chapter 13 of the RIA. Also included as an appendix to that chapter are
sensitivity analyses for several key inputs.
---------------------------------------------------------------------------
\246\ Actual fuel program compliance costs are expected to be
spread more evenly across years.
---------------------------------------------------------------------------
Market Impact Analysis. In the market analysis, we estimate how
prices and quantities of goods affected by the emission control program
can be expected to change once the program goes into effect. As
explained above, we estimated market impacts for only the gasoline fuel
and PFC markets. The analysis relies on the baseline equilibrium prices
and quantities for each market and the price elasticity of supply and
demand. It predicts market reactions to the increase in production
costs due to the new compliance costs. It should be noted that this
analysis does not allow any other factors to vary. In other words, it
does not consider that manufacturers may adjust their production
processes or marketing strategies in response to the control program.
The market analysis results for 2009, 2012, 2015, and 2020 are
presented in Table VIII.F-1. With regard to the gasoline fuel program,
the market impacts are expected to be small, on average. The price of
gasoline fuel is expected to increase by less than 0.5 percent,
depending on PADD, with smaller increases during the program phase-in.
The expected reduction in quantity of fuel produced is expected to be
less than 0.1 percent.
The market impacts for the PFC program are expected to be more
significant. In 2009, the first year of the PFC program, the model
predicts a price increase of about seven percent for PFCs in states
that currently have regulations for PFCs and about 57 percent for those
that do not. Even with these large price increases, however, the
quantity produced is not expected to decrease by very much: less than
0.6 percent. These percent price increases and quantity decreases are
much smaller after the first five years. In 2015, the estimated PFC
price increase is expected to be less than two percent for states that
currently regulate PFCs and about 32.5 percent for states without such
regulations. The quantity produced is expected to decrease by less than
0.4 percent. The results for 2020 are substantially the same as 2015,
with a larger decrease in the number of PFCs produced.
Table VIII.F-1.--Summary of Market Impacts (2009, 2012, 2015, and 2020; 2003$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in price Change in quantity
Market Engineering cost ---------------------------------------------------------------------------
per unit Absolute Percent Absolute Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
2009
--------------------------------------------------------------------------------------------------------------------------------------------------------
[cent]/gallon [cent]/gallon ................. Million gallons
----------------------------------------------------------------------------------------------
Gasoline Fuel:
PADD 1 & 3........................................... 0.016 0.009 0.006 -0.9 -0.001
PADD 2............................................... 0.091 0.050 0.033 -2.7 -0.007
PADD 4............................................... 0.033 0.018 0.011 -0.1 -0.002
PADD 5 (w/out CA).................................... 0.007 0.004 0.002 -0.0 0.000
--------------------------------------------------------------------------------------------------------------------------------------------------------
$/can
Thousand cans
----------------------------------------------------------------------------------------------
Portable Fuel Containers:
States with existing programs........................ 0.77 0.76 6.9 -8.0 -0.07
States without existing programs..................... 2.70 2.68 57.5 -104.7 -0.57
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
[cent]/gallon
Million gallons
----------------------------------------------------------------------------------------------
Gasoline Fuel:
PADD 1 & 3........................................... 0.058 0.032 0.021 -3.3 -0.004
PADD 2............................................... 0.308 0.168 0.111 -9.7 -0.022
[[Page 8522]]
PADD 4............................................... 0.213 0.116 0.074 -0.8 -0.015
PADD 5 (w/out CA).................................... 0.140 0.768 0.046 -0.8 -0.009
--------------------------------------------------------------------------------------------------------------------------------------------------------
$/can
Thousand cans
----------------------------------------------------------------------------------------------
Portable Fuel Containers:
States with existing programs........................ 0.77 0.76 6.9 -8.5 -0.07
States without existing programs..................... 2.70 2.68 57.5 -111.1 -0.57
--------------------------------------------------------------------------------------------------------------------------------------------------------
2015
--------------------------------------------------------------------------------------------------------------------------------------------------------
[cent]/gallon
Million gallons
----------------------------------------------------------------------------------------------
Gasoline Fuel:
PADD 1 & 3........................................... 0.149 0.081 0.055 -8.9 -0.011
PADD 2............................................... 0.307 0.167 0.111 -10.4 -0.022
PADD 4............................................... 0.501 0.273 0.174 -1.8 -0.035
PADD 5 (w/out CA).................................... 0.997 0.544 0.327 -6.1 -0.065
--------------------------------------------------------------------------------------------------------------------------------------------------------
$/can
Thousand cans
----------------------------------------------------------------------------------------------
Portable Fuel Containers:
States with existing programs........................ 0.21 0.20 1.9 -2.4 -0.02
States without existing programs..................... 1.53 1.52 32.5 -66.7 -0.32
--------------------------------------------------------------------------------------------------------------------------------------------------------
2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
[cent]/gallon
Million gallons
----------------------------------------------------------------------------------------------
Gasoline Fuel:
PADD 1 & 3........................................... 0.149 0.081 0.055 -9.5 -0.011
PADD 2............................................... 0.307 0.167 0.111 -10.7 -0.022
PADD 4............................................... 0.501 0.273 0.174 -2.0 -0.035
PADD 5 (w/out CA).................................... 0.997 0.544 0.327 -6.4 -0.065
--------------------------------------------------------------------------------------------------------------------------------------------------------
$/can
Thousand cans
----------------------------------------------------------------------------------------------
Portable Fuel Containers:
States with existing programs........................ 0.21 0.20 1.9 -2.7 -0.02
States without existing programs..................... 1.53 1.52 32.5 -73.6 -0.32
--------------------------------------------------------------------------------------------------------------------------------------------------------
Economic Welfare Analysis. In the economic welfare analysis, we
look at the costs to society of the emission control program in terms
of losses to key stakeholder groups that are the producers and
consumers in the gasoline and PFC markets. These surplus losses are
combined with estimated vehicle compliance costs, gasoline fuel
savings, and government revenue losses to estimate the net economic
welfare impacts of the program. Detailed economic welfare results for
the rule are presented in Appendix C and are summarized below.
The estimated annual net social costs (total social costs less
gasoline fuel savings) for all years are presented in Table VIII.F-2.
These social costs follow the trend of the fuel program compliance
costs. Initially, the estimated social costs of the program are
relatively small as the gasoline program begins to phase in. The net
social costs increase to 2012, fall somewhat for 2013 and 2014 due to
changes in the fuel program compliance costs, and then increase again
in 2015, after which time the per-gallon costs are expected to be
stable. Some of the decrease in social costs in 2014 is also due to a
decrease in costs associated with the PFC program, since fixed costs
are fully amortized by 2014. The slight decrease in 2020 is due to the
end of the vehicle compliance costs, which are incurred in the 10-year
period from 2010 through 2019.
Table VIII.F-2.--Estimated Engineering Compliance and Social Costs
Through 2035
[Including fuel savings; $million; 2003$]
------------------------------------------------------------------------
Engineering
Year compliance Social costs
costs
------------------------------------------------------------------------
2007.................................... $29.5 $29.5
2008.................................... 51.3 51.3
2009.................................... 99.0 98.9
2010.................................... 161.9 161.7
2011.................................... 152.6 152.4
2012.................................... 228.7 228.5
2013.................................... 190.9 190.8
2014.................................... 150.8 150.7
2015.................................... 350.8 350.7
2016.................................... 354.5 354.4
2017.................................... 358.0 357.9
2018.................................... 361.9 361.8
2019.................................... 366.1 366.0
2020.................................... 359.5 359.4
2021.................................... 363.5 363.4
2022.................................... 367.1 367.0
2023.................................... 370.7 370.6
2024.................................... 374.7 374.6
2025.................................... 378.7 378.6
2026.................................... 383.1 383.0
[[Page 8523]]
2027.................................... 387.5 387.4
2028.................................... 391.6 391.4
2029.................................... 396.0 395.9
2030.................................... 400.1 400.0
2031.................................... 404.6 404.5
2032.................................... 409.2 409.1
2033.................................... 413.9 413.7
2034.................................... 418.6 418.4
2035.................................... 423.4 423.2
3% NPV (2006-2035)...................... 5,356.8 5,354.6
7% NPV (2006-2035)...................... 2,901.0 2,899.7
------------------------------------------------------------------------
Table VIII.F-3 shows how the social costs are expected to be shared
across stakeholders, for selected years. Information for all years can
be found in Appendix C. According to these results, consumers are
expected to bear approximately 99 percent of the cost of the PFC
program. This reflects the inelastic price elasticity on the demand
side of the market and the elastic price elasticity on the supply side.
The burden of the gasoline fuel program is expected to be shared more
evenly, with about 54.5 percent expected to be borne by consumers and
about 45.5 percent expected to be borne by producers. In all years, the
estimated loss to consumer welfare will be offset somewhat by the
gasoline fuel savings associated with PFCs. Beginning at about $11
million per year, these savings increase to about $76 million by 2015
as compliant PFCs are phased in. These savings continue for the life of
the PFCs; total annual savings increase as the number of cans increases.
Table VIII.F-3.--Summary of Estimated Social Costs, 2009, 2012, 2015, and 2020
[$million; 2003$]
----------------------------------------------------------------------------------------------------------------
Change in Change in
Market consumer producer Total
surplus surplus
----------------------------------------------------------------------------------------------------------------
2009
----------------------------------------------------------------------------------------------------------------
Gasoline U.S.................................................... -$28.5 -$23.8 -$52.3
(54.6%) (45.4%) ..............
PADD 1 & 3.................................................. -$6.7 -$5.6 -$12.2
PADD 2...................................................... -$20.6 -$17.2 -$37.8
PADD 4...................................................... -$0.9 -$0.7 -$1.6
PADD 5 (w/out CA)........................................... -$0.3 -$0.3 -$0.6
Portable Fuel Containers U.S.................................... -$57.5 -$0.4 -$57.9
(99.3%) (0.7%) ..............
States with existing programs............................... -$8.9 -$0.1 -$8.9
States without existing programs............................ -$48.7 -$0.3 -$49.0
-----------------------------------------------
Subtotal................................................ -$86.1 -$24.1 -$110.2
(78.1%) (22%) ..............
-----------------------------------------------
Fuel Savings.................................................... .............. .............. $11.3
Vehicle Program................................................. .............. .............. $0
-----------------------------------------------
Total................................................... .............. .............. -$98.9
----------------------------------------------------------------------------------------------------------------
2012
----------------------------------------------------------------------------------------------------------------
Gasoline U.S.................................................... -$110.7 -$92.3 -$203.0
(54.5%) (45.5%) ..............
PADD 1 & 3.................................................. -$24.8 -$20.7 -$45.5
PADD 2...................................................... -$73.2 -$61.0 -$134.2
PADD 4...................................................... -$5.9 -$4.9 -$10.9
PADD 5 (w/out CA)........................................... -$6.8 -$4.7 -$12.4
Portable Fuel Containers U.S.................................... -$61.1 -$0.4 -$61.5
(99.3%) (0.7%) ..............
States with existing programs............................... -$9.4 -$0.1 -$9.5
States without existing programs............................ -$51.7 -$0.4 -$52.1
-----------------------------------------------
Subtotal................................................ -$171.8 -$92.7 -$264.5
(65.0%) (35.0%) ..............
-----------------------------------------------
Fuel Savings.................................................... .............. .............. $48.5
Vehicle Program................................................. .............. .............. -$12.5
Total................................................... .............. .............. -$228.5
----------------------------------------------------------------------------------------------------------------
2015
----------------------------------------------------------------------------------------------------------------
Gasoline U.S.................................................... -$207.0 -$172.5 -$379.4
(54.5%) (45.5%) ..............
PADD 1 & 3.................................................. -$66.3 -$55.3 -$121.6
PADD 2...................................................... -$75.9 -$63.2 -$139.1
[[Page 8524]]
PADD 4...................................................... -$14.5 -$12.1 -$26.6
PADD 5 (w/out CA)........................................... -$50.3 -$41.9 -$92.2
Portable Fuel Containers U.S.................................... -$33.7 -$0.2 -$34.0
(99.3%) (0.7%) ..............
States with existing programs............................... -$2.7 $0.0 -$2.7
States without existing programs............................ -$31.0 -$0.2 -$31.3
-----------------------------------------------
Subtotal................................................ -$240.7 -$172.7 -$413.4
(58.2%) (41.8%) ..............
-----------------------------------------------
Fuel Savings.................................................... .............. .............. $75.5
Vehicle Program................................................. .............. .............. -$12.9
Total................................................... .............. .............. -$350.7
----------------------------------------------------------------------------------------------------------------
2020
----------------------------------------------------------------------------------------------------------------
Gasoline U.S.................................................... -$219.6 -$183.0 -$402.6
(54.5%) (45.5%) ..............
PADD 1 & 3.................................................. -$70.4 -$58.6 -$129.0
PADD 2...................................................... -$80.5 -$67.1 -$147.6
PADD 4...................................................... -$15.4 -$12.8 -$28.2
PADD 5 (w/out CA)........................................... -$53.4 -$44.5 -$97.8
Portable Fuel Containers U.S.................................... -$37.2 -$0.2 -$37.5
(99.3%) (0.7%) ..............
States with existing programs............................... -$3.0 $0.0 -$3.0
States without existing programs............................ -$34.3 -$0.2 -$34.5
-----------------------------------------------
Subtotal................................................ -$256.8 -$183.3 -$440.1
(58.4%) (41.6%) ..............
-----------------------------------------------
Fuel Savings.................................................... .............. .............. $80.7
Vehicle Program................................................. .............. .............. -$0
-----------------------------------------------
Total................................................... .............. .............. -$359.4
----------------------------------------------------------------------------------------------------------------
The present value of net social costs (discounted back to 2006) of
the standards through 2035, contained in Table VIII.F-2, is estimated
to be about $5.4 billion (2003$). This present value is calculated
using a social discount rate of three percent and the stream of
economic welfare costs through 2035. We also performed an analysis
using a seven percent social discount rate.\247\ Using that discount
rate, the present value of the net social costs through 2035 is
estimated to be about $2.9 billion (2003$).
---------------------------------------------------------------------------
\247\ EPA presents the present value of cost and benefits
estimates using both a three percent and a seven percent social
discount rate. According to OMB Circular A-4, ``the 3 percent
discount rate represents the `social rate of time preference' * * *
[which]
means the rate at which `society' discounts future
consumption flows to their present value''; ``the seven percent rate
is an estimate of the average before-tax rate of return to private
capital in the U.S. economy * * * [that]
approximates the
opportunity cost of capital.''
Table VIII.F-4.--Net Present of Estimated Social Costs 2007 through 2035, Discounted to 2006
[$million; 2003$]
----------------------------------------------------------------------------------------------------------------
Change in Change in
Market consumer producer Total
surplus surplus
----------------------------------------------------------------------------------------------------------------
Gasoline, U.S................................................... -$3,115.4 -$2,596.2 -$5,711.6
(54.5%) (45.5%)
PADD 1 & 3.................................................. -$959.7 -$799.8 -$1,759.5
PADD 2...................................................... -$1,260.4 -$1,050.4 -$2,310.8
PADD 4...................................................... -$210.8 -$175.6 -$386.4
PADD 5 (w/out CA)........................................... -$229.5 -$570.4 -$1,254.8
-$684.5 .............. ..............
Portable Fuel Containers US..................................... -$754.9 -$5.0 -$759.9
(99.3%) (0.7%)
States with existing programs............................... -$78.7 -$0.5 -$79.3
States without existing programs............................ -$676.2 -$4.5 -$680.7
-----------------------------------------------
[[Page 8525]]
Subtotal................................................ -$3870.3 -$2,601.2 -$6,471.6
59.8% 40.2%
-----------------------------------------------
Fuel Savings.................................................... $1,208.0 .............. $1,208.0
Vehicle Program................................................. .............. -$91.1 -$91.1
-----------------------------------------------
Total....................................................... -$2,662.3 -$2,692.3 -$5,354.6
----------------------------------------------------------------------------------------------------------------
Table VIII.F-4 shows the distribution of total surplus losses for
the cumulative net social costs of the rule. This analysis includes the
estimated social costs from 2007 through 2035, discounted to 2006 at a
3 percent discount rate. These results suggest that consumers will bear
about 60 percent of the total social costs associated with the PFC and
gasoline fuel programs for that period. The consumer share of the NPV
social costs is about $3,870 million, or about 60 percent of the total.
Of that loss of consumer surplus, about $3,115 million (about 80
percent) is from the gasoline fuel program. When the total costs of the
program are taken into account, including the fuel savings and the
vehicle program costs, the loss of consumer surplus decreases to about
$2,662.3 million (about 50 percent of the social costs of the program).
IX. Public Participation
Many interested parties participated in the rulemaking process that
culminates with this final rule. This process provided opportunity for
submitting written public comments following the proposal that we
published on March 29, 2006 (71 FR 15804). We considered these comments
in developing the final rule. In addition, we held a public hearing on
the proposed rulemaking on April 12, 2006, and we have considered
comments presented at the hearing.
Throughout the rulemaking process, EPA met with stakeholders
including representatives from the fuel refining and distribution
industry, automobile industry, emission control manufacturing industry,
gas can industry, environmental organizations, states, interests, and
others.
We have prepared a detailed Summary and Analysis of Comments
document, which describes comments we received on the proposal and our
response to each of these comments. The Summary and Analysis of
Comments is available in the docket for this rule at the internet
address listed under ADDRESSES, as well as on the Office of
Transportation and Air Quality Web site (http://www.epa.gov/otaq/
toxics.htm#mobile). In addition, comments and responses for key issues
are included throughout this preamble.
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under section 3(f)(1) of Executive Order (EO) 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to ``have an annual effect on
the economy of $100 million or more'' and ``raise novel legal and
policy issues.'' Accordingly, EPA submitted this action to the Office
of Management and Budget (OMB) for review under EO 12866, and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
A final Regulatory Impact Analysis has been prepared and is
available in the docket for this rulemaking and at the docket internet
address listed under ADDRESSES.
B. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
information collection requirements are not enforceable until OMB
approves them.
The Agency will collect information to ensure compliance with the
provisions in this rule. This includes a variety of requirements, both
for vehicle manufacturers, fuel producers, and portable fuel container
manufacturers. Information-collection requirements related to vehicle
manufacturers are in EPA ICR #0783.52 (OMB Control Number 2060-
0104); requirements related to fuel producers are in EPA ICR
#1591.22 (OMB Control Number 2060-0277); requirements related
to portable fuel container manufacturers are in EPA ICR
#2213.02. For vehicle and fuel standards, section 208(a) of the
Clean Air Act requires that manufacturers provide information the
Administrator may reasonably require to determine compliance with the
regulations; submission of the information is therefore mandatory. We
will consider confidential all information meeting the requirements of
section 208(c) of the Clean Air Act. For portable fuel container
standards, recordkeeping and reporting requirements for manufacturers
would be pursuant to the authority of sections 183(e) and 111 of the
Clean Air Act.
As shown in Table X.B-1, the total annual burden associated with
this rule is about 28,000 hours and $1,993,723, based on a projection
of 521 respondents. The estimated burden for vehicle manufacturers and
fuel producers is a total estimate for both new and existing reporting
requirements. The portable fuel container requirements represent our
first regulation of these containers, so those burden estimates reflect
only new reporting requirements. Burden means the total time, effort,
or financial resources expended by persons to generate, maintain,
retain, or disclose or provide information to or for a Federal agency.
This includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
[[Page 8526]]
Table X.B-1.--Estimated Burden for Reporting and Recordkeeping Requirements
----------------------------------------------------------------------------------------------------------------
Number of Annual burden
Industry sector respondents hours Annual costs
----------------------------------------------------------------------------------------------------------------
Vehicles........................................................ 35 770 $80,900
Fuels........................................................... 476 26,592 *1,888,032
Portable fuel containers........................................ 10 638 24,791
-----------------------------------------------
Total....................................................... 521 28,000 1,993,723
----------------------------------------------------------------------------------------------------------------
*Does not include non-postage purchased services of approximately $1,988,000.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
When this ICR is approved by OMB, the Agency will publish a
technical amendment to 40 CFR part 9 and 48 CFR chapter 15 in the
Federal Register to display the OMB control number for the approved
information collection requirements contained in this final rule. EPA
received various comments on the rulemaking provisions covered by the
ICRs, but no comments on the paperwork burden or other information in
the ICRs. All comments that were submitted to EPA are considered in the
relevant Summary and Analysis of Comments, which can be found in the docket.
C. Regulatory Flexibility Act (RFA), as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq.
1. Overview
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201 (see table below); (2) a small governmental jurisdiction that
is a government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field. The
following table provides an overview of the primary SBA small business
categories potentially affected by this regulation:
------------------------------------------------------------------------
Defined as small
entity by SBA if NAICS Codes
Industry less than or equal \a\
to:
------------------------------------------------------------------------
Light-duty vehicles:
--vehicle manufacturers 1,000 employees..... 336111
(including small volume
manufacturers).
--independent commercial $6 million annual 811111
importers. sales. 811112
811198
--alternative fuel vehicle 100 employees....... 424720
converters.
1,000 employees..... 335312
$6 million annual 811198
sales.
Gasoline fuel refiners............ 1500 employees \b\.. 324110
Portable fuel container
manufacturers:
--plastic container 500 employees....... 326199
manufacturers.
--metal gas can manufacturers. 1,000 employees..... 332431
------------------------------------------------------------------------
Notes:
\a\ North American Industrial Classification System
\b\ EPA has included in past fuels rulemakings a provision that, in
order to qualify for EPA's small refiner flexibilities, a refiner must
also produce no greater than 155,000 bpcd crude capacity.
Pursuant to section 603 of the RFA, EPA prepared an initial
regulatory flexibility analysis (IRFA) for the proposed rule and
convened a Small Business Advocacy Review Panel (SBAR Panel, or the
`Panel') to obtain advice and recommendations of representatives of the
regulated small entities. A detailed discussion of the Panel's advice
and recommendations is found in the Panel Report (see Docket EPA-HQ-
OAR-2005-0036). A summary of the Panel's recommendations is presented
at 71 FR 15922 (March 29, 2006).
As required by section 604 of the RFA, we also prepared a final
regulatory flexibility analysis (FRFA) for today's final rule. The FRFA
addresses the issues raised by public comments on the IRFA, which was
part of the proposal of this rule. The FRFA is available for review in
Chapter 14 of the RIA and is summarized below.
Key elements of our FRFA include:
? A description of the reasons the Agency is considering
this action, and the need for, and objectives of, the rule;
? A summary of the significant issues raised by the public
comments on the IRFA, a summary of the Agency's assessment of those
issues, and any changes made to the proposed rule as a result of those
comments;
? A description of the types and number of small entities to
which the rule will apply;
? A description of the reporting, recordkeeping, and other
compliance requirements of the rule;
? An identification, to the extent practicable, of all
relevant Federal rules that may duplicate, overlap, or conflict with
the rule; and
? A description of the steps taken to minimize the
significant economic impact on small entities consistent with
[[Continued on page 8527]]
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